Climate Regulation: United States

International Agreements and Regulations

The United States has increased its focus on both domestic and international climate change regulation. On November 11, 2014, the US struck a bilateral agreement with China under which both nations will seek to significantly reduce greenhouse gas (GHG) emissions. Under the agreement, the US pledged to reduce GHG emissions to 26% to 28% below 2005 levels by 2025. On March 31, 2015, the US announced its commitment to reduce GHG emissions to 26% to 28% below 2005 levels by 2025 as the basis for its Intended Nationally Determined Contribution at the United Nations Climate Change Conference (COP21). In April 2016, the US signed the Paris Agreement arising from COP21, and President Obama is expected to ratify the Paris Agreement before the end of 2016. In June 2016, the US, Mexico, and Canada announced a joint goal of achieving 50% clean power generation by 2025, across all three countries. This goal may lead to increased trans-border transmission and energy infrastructure projects. The three nations also agreed to reduce methane emissions from the oil and gas sector by 40% to 45% by 2025. The US previously ratified the United Nations (UN) Framework Convention on Climate Change on October 15, 1992, which became effective on March 21, 1994. The US signed the Kyoto Protocol on December 11, 1998, but it does not apply to the US as the US Congress did not ratify it. The US also is a party to the Montreal Protocol on Substances that Deplete the Ozone Layer (Montreal Protocol) since its finalization in 1987. The Montreal Protocol and the related US implementing legislation places certain restrictions on the production and use of ozone-depleting substances, including hydrochlorofluorocarbons (HCFCs) and chlorofluorocarbons (CFCs), many of which are potent GHGs. Under the Montreal Protocol, the US must incrementally decrease HCFC consumption and production, with a complete HCFC phaseout by 2030. Other restrictions and regulations apply to the use of CFCs. On November 6, 2015, all 197 parties to the Montreal Protocol agreed on a process, called the Dubai Pathway, to further manage and reduce HCFC emissions. Under the Dubai Pathway, the parties will meet in October 2016 to consider amending the Protocol to reduce, and eventually eliminate, the use of hydrofluorocarbons (HFCs), which are potent greenhouse gases frequently used as HCFC and CFC substitutes, widely used in refrigeration systems.

The US lacks a comprehensive policy to regulate GHG emissions at the national level. In the absence of a national change program, US regulatory agencies have taken numerous sector-based actions to reduce GHG emissions and often look to international standards and data when designing domestic GHG programs. For example, the US Environmental Protection Agency (EPA) often cites GHG emissions data and climate change research created by the UN’s Intergovernmental Panel on Climate Change (IPCC). Similarly, EPA and the Federal Aviation Administration (FAA) traditionally have worked with the International Civil Aviation Organization (ICAO) to establish aircraft emissions standards. EPA currently is in the midst of a multi-year rulemaking process to align US GHG emissions standards for aircraft with those created by ICAO.

Main Regulatory Policies

Federal Developments

Despite several promising attempts, the US Congress has failed to enact comprehensive climate change legislation. In the absence of legislation, President Obama has acted to reduce GHG emissions by using preexisting regulatory authority, primarily under the federal Clean Air Act (CAA). On June 25, 2013, President Obama released his Climate Action Plan (CAP), which sets forth various goals for achieving domestic GHG reductions. While the CAP has no legal effect itself, it serves as a roadmap for the Obama Administration’s climate change initiatives. The centerpiece of these initiatives, the Clean Power Plan, is discussed below. The Climate Action Plan also outlines the current US strategy for deploying renewable energy, increasing energy efficiency, and spurring international action on climate change.

In March 2016, the US Supreme Court halted the implementation of the Clean Power Plan until the resolution of legal challenges in the US Court of Appeals for the DC Circuit. Oral arguments in the case were held in September 2016 before the full panel of judges on the DC Circuit. Although a final decision could take several months, the DC Circuit will determine whether the Clean Power Plan violates the Clean Air Act and illegally deprives states of regulatory authority. The losing party is likely to seek review by the US Supreme Court.

In August 2016, the White House Council on Environmental Quality published final guidance on the consideration of GHG emissions in National Environmental Policy Act (NEPA) reviews. The guidance directs federal agencies to analyze a project’s GHG emissions and how climate change may affect the project over time. The guidance indicates that agencies should project GHG emissions via a quantitative analysis when the necessary data and methods are reasonably available. However, the guidance does not offer a specific level of GHG emissions that would be considered significant enough to require an environmental impact statement.

Federal Climate Change Regulation

A series of regulatory actions and related court decisions have created a regulatory framework under which EPA regulates GHG emissions from various sectors. In 2007, the Supreme Court issued its seminal opinion in Massachusetts v. EPA, finding that GHGs met the definition of "air pollutant" under the CAA. The Court further held that EPA had authority to regulate GHG emissions from new motor vehicles, and was obligated to do so if the Agency determined that motor vehicle GHG emissions endangered public health and welfare. In 2009 EPA issued its Endangerment Finding, determining that the six primary GHGs recognized by the UN may reasonably be anticipated to endanger public health and welfare. Concurrently, EPA determined that GHG emissions from motor vehicles contribute to pollution that endangers public health and welfare.

Transportation Sector

The Endangerment Finding triggered a series of GHG regulatory efforts, beginning with EPA’s 2010 issuance of GHG emission and fuel economy standards for new light-duty vehicles and engines starting with model year 2012 (the Tailpipe Rule). In September 2011, in coordination with the National Highway Traffic Safety Administration (NHTSA), EPA established fuel economy standards for light-duty cars and trucks in model years 2012–2016 (first phase) and 2017–2025 (second phase). Together, these standards are projected to result in an average industry fleet-wide level of 163 grams/mile of carbon dioxide (CO2) in model year 2025, which is equivalent to 54.5 miles per gallon (mpg).

In September 2011, EPA and NHTSA, in collaboration with the California Air Resources Board (CARB), also established GHG emissions and fuel economy standards for medium and heavy-duty trucks. Phase one of this program covers vehicles built for the 2014 to 2018 model years and is estimated to reduce CO2 emissions by about 270 million metric tons (MMT) over the life of those vehicles. In August 2016, EPA and NHTSA finalized Phase 2 of this program, covering model years 2018–2027 for certain trailers and model years 2021–2027 for semi-trucks, large pickup trucks, vans and all types and sizes of buses and work trucks. EPA expects these standards to reduce GHG emissions by about 1.1 billion MMT.

On August 15, 2016, EPA promulgated an endangerment finding for aircraft (the Aircraft Endangerment Finding). The Aircraft Endangerment Finding determined that GHG emissions from certain classes of aircraft engines, including those used by most large commercial aircraft, contribute to the air pollution that causes climate change and endangers public health and welfare. EPA has not yet proposed aircraft engine GHG emission standards, but the Aircraft Endangerment Finding represents a step in that direction, much as the 2009 Endangerment Finding was the first step towards regulating GHG emissions from motor vehicles. EPA is working to align any eventual standards with those issued by ICAO. According to EPA, GHG emissions from aircraft represent 12% of transport-related GHG emissions in the US and 3% of total US GHG emissions.

Electric Power Sector

When the Tailpipe Rule took effect in January 2011, GHGs became a "regulated pollutant" under the CAA. Accordingly, EPA undertook various rulemaking processes to incorporate GHG emissions into programs applicable to stationary sources, which include the Title V operating permit program and the Prevention of Significant Deterioration (PSD) program. These permitting programs are discussed further in "GHG Emission Permits or Approvals." 

In the wake of Massachusetts v. EPA, a coalition of states and environmental groups sued EPA to compel the agency to issue performance standards for GHG emissions from fossil fuel-fired power plants. In 2010, EPA agreed to propose and finalized two separate New Source Performance Standards (NSPSs) for CO2 emissions, one for existing electric generating units (EGUs), and another for new, modified and reconstructed EGUs. EPA issued initial proposals for new sources in 2012 and 2013. However, in conjunction with the CAP, President Obama instructed EPA to re-propose new source GHG standards and to issue GHG performance standards for existing power plants. In August 2015, this process culminated with the issuance of the Clean Power Plan (CPP), which establishes the GHG NSPS for existing power plants, and the GHG NSPS for new, modified and reconstructed EGUs.

Existing EGUs: the Clean Power Plan

The CPP is the most significant attempted US action on climate change at the national level to date. As noted above, the rule has stayed pending review by the DC Circuit, and any future review by the US Supreme Court. Many observers expect that the US Supreme Court will eventually determine the fate of the regulation. Relying on Section 111(d) of the CAA, the CPP establishes GHG emissions standards for existing fossil fuel-fired power plants. These emissions standards are based on the Best System of Emission Reduction (BSER) as determined by EPA. Under the CPP, EPA has defined BSER as consisting of three building blocks:

  • Improving operating efficiency at affected power plants.
  • Substituting generation from lower-emitting EGUs for generation from higher-emitting EGUs.
  • Increasing renewable energy-generating capacity to displace power generated by fossil fuel-fired power plants.

These building blocks are applied to each state’s unique energy mix to calculate a state-specific GHG emissions rate target. To encourage and enable cap-and-trade programs as a compliance mechanism, EPA also issued statewide mass-based standards that are extrapolated from the rate-based standards and reflect baseline generation in each state.

If the CPP survives judicial review, states will be required to develop State Implementation Plans (SIPs) to achieve their respective GHG emission reduction goals at either the individual power plant level or on a statewide basis. States have considerable flexibility to design compliance measures, which may include cap-and-trade programs, renewable power programs, individual plant emissions limitations, energy efficiency measures, and other mechanisms to reduce overall GHG emissions from the power sector. States are permitted to propose plans that allow for interstate trading without formally entering into multi-state plans, which reduces the logistical barriers for states that generally wish to participate in trading but do not want to develop or participate in a formal multi-state plan. States that fail to submit an approvable plan will be subject to a federal implementation plan issued by EPA, which, as currently proposed, would require those states to participate in a GHG emissions trading program.

New, Modified, and Reconstructed EGUs

Concurrent with its release of the CPP, EPA released a final rule to limit GHG emissions from new, modified, and reconstructed EGUs. EPA’s final rule for new EGUs not only serves as a stand-alone regulation but also provides the legal underpinning for the issuance of the CPP. Under EPA’s interpretation of the CAA, a 111(b) rule for EGUs is necessary to trigger the authority to issue the 111(d) rule.

EPA’s final NSPS rule limits GHG emissions from new, modified, and reconstructed EGUs. The new-source rule is also based on the concept of BSER and establishes separate GHG performance standards for coal and natural gas-fired power plants. New coal-fired EGUs must emit no more than 1,400lbs CO2/megawatt hour (MWh), while almost all new natural gas-fired EGUs must emit no more than 1,000lbs CO2/MWh. The coal-fired EGU standard will almost certainly require the use of at least partial carbon capture and storage (CCS) technology since even the most advanced type of coal plants achieve a CO2 emission rate of around 1,700– 1,800lbs/MWh. The standard applicable to natural gas-fired power plants is achievable using advanced natural gas combined cycle (NGCC) technology. EPA forecasts that its new-source standards will have limited cost and GHG impacts through 2022, given the low price of natural gas and limited interest in constructing new coal-fired power plants in the US.


In 2011, EPA published a final rule that deferred GHG permitting requirements for biomass-fired and other biogenic sources until July 21, 2014 (Deferral Rule). This rule had the effect of temporarily exempting these sources from GHG permitting under the PSD and Title V programs. However, on July 12, 2013, the DC Circuit Court vacated the Deferral Rule, which removed the temporary exemption and subjected biomass facilities to GHG permitting. While the court held that EPA had not adequately justified its decision to exempt biomass emissions temporarily, it left open the possibility that EPA could permanently exempt biomass from GHG permitting if EPA could identify proper CAA authority to do so. Biomass industries and energy producers have asked EPA to create such a permanent exemption; in the interim, biomass issues are being handled individually during the Title V and PSD permitting processes.

EPA also is in the midst of a process to evaluate the impact of biogenic CO2 emissions from stationary sources. In November 2014, EPA released its Revised Framework for Assessing Biogenic CO2 Emissions from Stationary Sources, which incorporates information from the scientific community and other stakeholders. EPA plans to continue refining this assessment through the second round of peer review with the Science Advisory Board (SAB). EPA’s work on this continues, and in April 2016, EPA held a workshop entitled Fostering Constructive Dialogue on the Role of Biomass in Stationary Source Carbon Strategies. There is a current difference of opinion across various stakeholders on how to calculate biogenic CO2 emissions and the carbon benefits associated with the use of different forms of biomass.

The CPP did little to clarify the role of biomass. The CPP generally provides that states may rely on qualifying biomass to meet their state goals, but that such use will require demonstrations by the state that the biomass feedstocks contribute to net reductions in CO2 emissions. EPA did not provide robust standards for assessing biomass emissions and instead left it to the states to assess the CO2 emissions benefits of different biomass feedstocks. The CPP also references sustainable forestry and agriculture as tools for reducing dependence on fossil fuels but does not incorporate a specific role for biomass in state implementation plans. As a result, the precise role of biomass in the US remains uncertain, at least until EPA develops a broader biomass rule or a comprehensive biogenic CO2 emissions accounting mechanism.

Oil and Gas Sector

In 2012, EPA promulgated NSPSs for the Crude Oil and Natural Gas Production source category that regulate volatile organic compound emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers, storage vessels and leaking components at natural gas processing plants, and sulfur dioxide emissions from natural gas processing plants. EPA revised these standards in 2013, 2014 and early 2015. EPA also enacted revisions to the National Emission Standards for Hazardous Air Pollutants for Oil and Natural Gas Production Facilities. While not directly regulating GHGs, EPA predicted that these regulations would result in significant climate co-benefits due to anticipated methane reductions.

In the spring of 2014, President Obama released a Strategy to Reduce Methane Emissions that identified key sources of methane emissions (landfills, coal mines, agriculture, and the oil and gas sector) and set forth a plan to reduce GHG emissions from those sources. In January 2015, the Obama Administration announced a new goal to cut methane emissions from the oil and gas sector by 40% to 45% over the next decade.

In June 2016, EPA published two final rules in support of President Obama’s methane reduction initiative. First, EPA adopted the Final Source Determination Rule to clarify what onshore oil and natural gas facilities collectively constitute the stationary source for purposes of the New Source Review and Title V permitting. The rule excludes facilities located beyond a quarter of a mile from the stationary source, and allows case-by-case evaluation of whether facilities located within a quarter of a mile are part of the stationary source based on the common sense notion of a plant. Higher levels of emissions from the aggregation of multiple sources can trigger applicability of more burdensome and costly air permit requirements.

Second, in amendments to the NSPS for the oil and gas sector, EPA established first-ever methane emissions limits for certain new, reconstructed, and modified facilities, including hydraulic fracturing wells. An important component of the rule requires operators to employ a leak detection program to control fugitive emissions from leaking equipment. EPA estimates the final NSPS will reduce 510,000 short tons of methane by 2025, equivalent to reducing 11 million metric tons of carbon dioxide. Contemporaneous with this NSPS amendment EPA issued the first draft of an Information Collection Request (ICR) to gather information in support of future methane regulations for existing oil and gas sources. The final ICR will consist of an operator survey requesting information on the number and types of equipment at all onshore oil and gas production facilities, and a facility survey requesting emissions information from a representative sample of facilities. EPA anticipates that the operator survey will begin in the fall of 2016.

Energy Efficiency

To date, national-level energy efficiency policies have relied more on voluntary and cooperative measures than legislative mandates, though there are a few exceptions. On April 30, 2015, President Obama signed a bill designed to improve building efficiency standards. Reflecting more modest aspirations than previously proposed energy efficiency bills, this recent legislation may nonetheless indicate a growing bipartisan consensus on energy efficiency. Despite the lack of significant national mandates, energy efficiency has gained significant traction in the US as a mechanism for avoiding increased energy consumption and reducing GHG emissions.

President Obama has undertaken a series of executive actions designed to raise awareness and increase energy efficiency in the US. For example, the Office of Energy Efficiency and Renewable Energy (EERE) supports research into energy-saving technologies for deployment across the residential, manufacturing and building sectors. EERE’s Building Technologies Office has issued 42 new or updated efficiency standards for appliance and equipment energy efficiency since 2009. In addition, the US Department of Energy (DOE) runs the Federal Energy Management Program, which focuses on reducing energy consumption and increasing the proportion of renewable energy utilized at federal agencies. The DOE also runs a Better Buildings program, with a goal of increasing building energy efficiency by 20% over the next decade across the commercial, public, industrial, and residential sectors. This cooperative program focuses on outreach, knowledge transfer, and market-driven energy efficiency solutions. On August 30, 2012, President Obama signed Executive Order 13624, Accelerating Investment in Industrial Energy Efficiency, which focused on increasing combined heat and power (CHP) systems and established a national goal of creating 40 gigawatts of new CHP capacity by 2020. On March 19, 2015, President Obama signed Executive Order 13693, Planning for Federal Sustainability in the Next Decade, which requires federal agencies to reduce energy intensity 2.5 percent annually through 2025, compared to a baseline year of FY 2015. This has led to significant investments by the federal government in energy efficiency measures. Through these and other programs, the federal government creates incentives and provides support for energy efficiency and related technologies.

Regional Climate Change Programs

The Regional Greenhouse Gas Initiative (RGGI) encompasses the eastern states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. Collectively, RGGI states account for about 20% of the US gross domestic product. RGGI was the first market-based GHG reduction scheme in the US and operates a cap-and-trade program covering the power sector. RGGI lowered its GHG emissions cap beginning in 2014, to 91 million short tons, with annual follow-on decreases of 2.5% from 2015 to 2020. Currently, various industry and environmental stakeholder groups are seeking a further tightening of RGGI’s GHG emissions caps beyond 2020. Membership in RGGI is voluntary and subject to change. New Jersey withdrew from RGGI in 2011, while Pennsylvania’s current governor supports joining RGGI. As states seek mechanisms for complying with the CPP, additional states may consider joining RGGI. RGGI and related issues are discussed further in "GHG Emission Allowances."

The Western Climate Initiative (WCI) launched in 2007, but after many years of work by certain states in the US and provinces in Canada, it has yet to develop into a functioning program and appears unlikely to do so. It did lead to the development of WCI, Inc, a non-profit corporation that provides administrative and technical services to the GHG emission allowance trading schemes of California and Quebec. California’s Cap-and-Trade program discussed further below currently allows for other jurisdictions to link with it provided that certain criteria are met, and such a linkage exists between California and Quebec. The Canadian province of Ontario is poised to join this program, with both California and Ontario undertaking significant regulatory processes to enable this to occur beginning 2018. The State of Washington also has entertained linking with California and these other jurisdictions. California’s regulatory amendments process for the Cap-and-Trade program, which began in 2016 and is expected to be completed in mid-2017, includes proposed amendments that would facilitate more diverse linkage options that may assist Washington in linking with it.

State Climate Change Programs

California’s Global Warming Solutions Act, also known as AB 32, was signed into law on September 27, 2006. AB 32 established a mandate to reduce GHG emissions to 1990 levels by 2020 and granted broad authority to CARB to develop and implement a broad strategy to achieve that goal. On September 8, 2016, Governor Brown signed into law a pair of bills, SB 32 and AB 197, that amended AB 32 in several ways. Most importantly, SB 32 extended and expanded the state’s commitment to reducing GHG emissions, establishing a new reduction target of 40% below 1990 levels by 2030. CARB’s strategy to achieve these emission reduction goals is set forth in its Scoping Plan, which summarises the state’s diverse set of GHG emission reduction programs (several of which are administered by state agencies other than CARB). These include programs in nearly every sector of the economy, including energy (e.g., regional balancing markets, efficiency), transportation (e.g., zero emission vehicles, low-carbon fuel standard, high-speed rail system), agriculture (e.g., methane capture standard), water (e.g., conservation programs), waste management (e.g., eliminate disposal of organic material at landfills), and natural lands (e.g., forest carbon plan). In CARB’s 2014 updated Scoping Plan, the 2020 cap on annual GHG emissions was set at 431 million short tons, which CARB calculates as an emission reduction goal of 78 million short tons below predicted 2020 business-as-usual emissions (509 million short tons). In 2016 CARB began working on another update to its Scoping Plan to account for an emissions target of 40% below 1990 levels by 2030 (which had been established by Executive Order prior to the passage of SB 32).

Although it accounts for only about 30% of the emission reductions under the current Scoping Plan (23 of the 78 million), the central feature is a multi-sector cap-and-trade GHG emissions program, which was first implemented in 2013. The program creates the second-largest carbon market in the world, after the European Union’s, and covers 85% of all GHG emissions in California. The program began with the power and industrial sectors, and in 2015 expanded to cover transportation and heating fuels. AB 32 mandates GHG emission reductions by 2020 only, but as noted above, SB 32 was enacted in 2016, extending the emission reduction mandate to 2030. Executive orders establish a further GHG emission reduction goal of 80% below 1990 levels by 2080. As noted above, in 2016 CARB undertook a regulatory amendments process for its Cap-and-Trade regulation and its accompanying GHG emissions monitoring regulation; the amendments are set to be finalized in mid-2017. These amendments will assist CARB in implementing the program through 2030 and prepare California to comply with the CPP. There is a degree of uncertainty regarding the Cap-and-Trade program and its regulations, however. While SB 32 extended and expanded the GHG emission reduction mandate to 2030, it did not expressly authorize the Cap-and-Trade program as the market-based mechanism for achieving a portion of these emission reductions. Indeed, the language in its companion bill, AB 197, appears to require CARB to prioritize direct GHG emission reduction measures over market-based measures. A legal challenge that contends that the allowance auctions that are a central part of the Cap-and-Trade program constitute an illegal tax, the case known as California Chamber of Commerce v. CARB, is pending before the California Court of Appeal for the Third District; a decision is anticipated by early 2017. If the Court strikes down the allowance auctions, it is not clear what form the Cap-and-Trade program will take thereafter or even if it will survive. Whichever side loses is sure to seek review by the California Supreme Court, and review is likely to be granted given the importance of the case. Most commentators anticipate that the current legal uncertainty will be largely resolved in 2017, by either the California Supreme Court or the California legislature. The Clean Energy and Pollution Reduction Act of 2015, also known as SB 350, established statewide goals for 2030 of 50% electricity generation from renewable resources (i.e., a renewable portfolio standard of 50%) and doubling energy efficiency in electricity and natural gas usage (in effect, a green buildings initiative) also plays an important role in California’s climate change efforts.

Following California’s lead, Massachusetts and Connecticut also have enacted GHG emission reduction legislation. The Massachusetts Global Warming Solutions Act, enacted in 2008, targets a reduction in statewide GHG emissions of 25% from 1990 levels by 2020, and an 80% reduction from 1990 levels by 2050. The legislation is not self-implementing, but instead creates a framework for reducing GHG emissions from various sectors, such as electricity, transportation, and buildings. In 2016, the Massachusetts Supreme Judicial Court ruled that current efforts were insufficient to achieve the goals of the Global Warming Solutions Act and ordered the state to set firm limits on GHG emissions for various sectors. Somewhat less ambitious, Connecticut’s Global Warming Solutions Act, also adopted in 2008, targets a reduction of statewide GHG emissions of 10% from 1990 levels by 2020, with an 80% reduction from 2001 levels required by 2050. These laws are driving increased activity in Massachusetts and Connecticut in a variety of areas, including a focus on renewable energy development, energy efficiency, and reduction of fossil fuel use. Other states have implemented less ambitious programs aimed at reducing GHG emissions, primarily related to the power sector. For example, Oregon, Montana, Washington, New York, Illinois, and Minnesota all have enacted some form of requirements related to GHG emissions from new electric generating facilities. Some states are beginning to broaden their GHG reduction efforts beyond the electric power sector. In June 2016, Washington released draft regulations that would establish a multi-sector GHG emissions reduction scheme, requiring annual reductions of 1.7% in GHG emissions from each covered facility. The program has some cap-and-trade elements as well, allowing a certain percentage of compliance obligations to be met through the retirement of emissions allowances and offset credits obtained from other programs. Washington is exploring linkage with California’s Cap-and-Trade program, which would provide a source of such allowances and credits. At the same time, Washington residents will vote in late 2016 on whether to adopt a state-wide carbon tax, which would begin at US$15 per tonne of carbon in the first year and increase to US$25 per tonne in year two, with smaller annual increases thereafter. Oregon is also considering establishing a broader cap-and-trade program, potentially with linkages to California, Washington, and other states. Two factors have increased state-level activity over the past two years: greater public support for GHG regulation and the need for states to comply with the federal CPP and other GHG programs. GHG reduction efforts are expanding across the US, but unevenly, with coastal states generally more receptive to GHG reduction programs than inland states

National Regulatory Authorities

EPA is the primary national regulatory authority with responsibility for climate regulation. EPA’s authority includes promulgation and enforcement of CAA standards for GHG emissions for both mobile and stationary sources, GHG reporting programs, adaptation to a changing climate, and protection of drinking water aquifers under the federal Safe Drinking Water Act with regard to CCS underground injection technologies.

NEPA requires federal agencies to consider potential environmental impacts associated with major federal actions that may significantly affect the environment. The Council on Environmental Quality (CEQ) is charged with ensuring federal agencies comply with NEPA. On February 18, 2010, CEQ issued Draft NEPA Guidance on Consideration of the Effects of Climate Change and Greenhouse Gas Emissions to help federal agencies address climate change impacts under NEPA. Most federal agencies now consider climate change during the NEPA process. On August 2, 2016, the CEQ released its final guidance on how federal agencies should consider the impacts of their actions on climate change. In particular, agencies must now make efforts to quantify projected GHG emissions resulting from federal approvals, whenever the data and tools exist to quantify such emissions. The guidance also lays out standards for describing climate change impacts and counsels agencies to consider alternative approaches to each project that would increase resilience to climate change.

In July 2015, the US Government Interagency Working Group on the Social Cost of Carbon revised the social cost of carbon (SCC) estimates to reflect updates to the underlying models. As an example, using 2015 emissions and a 3% discount factor, the SCC is US$36. That cost will rise to US$50 a metric ton in 2030 and US$69 a metric ton in 2050. The SCC, which was designed for federal agencies to utilize in cost-benefit analyses of regulatory actions that impact cumulative global emissions, sets the incremental cost to society of each metric ton of CO2 emitted and varies by emissions year and assumed discount rate. This SCC has been widely criticized by industry as having been increased without appropriate public process or analysis; at the same time, many environmental advocacy groups believe the figure is too low. In August 2016 the 7th US Circuit Court of Appeals upheld the Department of Energy’s use of the Social Cost of Carbon metric in an energy efficiency rulemaking action. Further litigation over this metric may occur as its regulatory use expands.

National Emissions, Limits, and Projects

The most recent comprehensive GHG emissions data for the US is EPA’s 2016 Inventory of US Greenhouse Gas Emissions and Sinks, which covers the period from 1990 through 2014. Mandatory GHG reporting began in 2011 for certain industries and in 2012 for others. As a result, EPA’s 2016 report includes robust GHG emissions data from various sectors of the US economy. According to EPA’s 2016 report, total US GHG emissions were 6,870.5MMT of CO2 equivalent (CO2e) in 2014. Leading sector-based emissions (in MMT CO2e) are as follows:

  • Electricity generation, 2,039.3.
  • Transportation, 1,737.6.
  • Industrial, 813.3.
  • Residential, 345.1.
  • Commercial, 231.9.

Other sectors were less significant. While CO2 emissions are the largest source of total GHG emissions in the US, in 2014 methane emissions across various sectors accounted for 730.8MMT CO2e, nitrous oxide accounted for 403.5MMT CO2e, and hydrofluorocarbons accounted for 166.7MMT CO2e. Other types of GHG emissions were less significant.

In 2014, the US experienced a 1% increase in GHG emissions from 2013. A cool winter led to an increase in residential and commercial heating, while an increase in transportation emissions resulted from an increase in miles traveled by vehicle and fuel use by on-road transportation. The US remains a large contributor to global GHG emissions. Globally, EPA estimates that 32,190MMT CO2 was added to the atmosphere through fossil fuel combustion in 2013, with the US contributing about 16%.

GHG emissions standards apply to private commercial entities to the extent that the entity is subject to regulation by the relevant national or state authority. See "Main Regulatory Policies" for a discussion of GHG emission limitations.

At the federal level, GHG emission reductions are primarily driven by CAA regulation, which does not currently contemplate emissions reduction projects or carbon offsets as compliance mechanisms. See "Main Regulatory Policies" for a discussion of GHG regulations, permitting requirements, and related GHG emission reductions. RGGI and California’s AB 32 both establish a system for GHG emission reductions. Carbon offsets are one component of complying with California’s GHG reduction scheme and are generated through several approved methodologies. See "Main Regulatory Policies" and "GHG Emission Allowances" for a broader discussion of RGGI and California’s program. See "Renewable Energy and Carbon Capture" for a discussion of renewable energy policies.

Domestic Climate Sector

Commercial climate business in the US is fragmented, largely due to the lack of comprehensive national climate change regulation. The CPP, discussed in "Main Regulatory Policies," may help to consolidate and increase the commercial climate sector. At present, the main drivers of the US climate sector are emissions credit trading under RGGI, emissions credit and offset trading under California’s AB 32, and biofuel requirements and related credit trading Emissions trading and commercial aspects of RGGI and California’s AB 32 are further discussed in "Main Regulatory Policies" and "GHG Emission Allowances." See "Renewable Energy and Carbon Capture" for a discussion of the renewable power sector.

Regulation of Emissions

Various national, regional and state programs exist in the US to regulate GHG emissions. See "Main Regulatory Policies" for a comprehensive discussion of US GHG emissions regulations.

GHG Emission Permits or Approvals

Certain stationary sources are required to obtain Title V operating permits and PSD permits for GHG emissions. These CAA programs are overseen and enforced by EPA. Under the CAA’s cooperative federalism approach, most states manage GHG permitting in conjunction with any applicable state laws or programs. Typically, any applicable NSPS GHG emissions limits (such as those imposed by the CPP or new source NSPS program) will be incorporated into a facility’s Title V operating permit.

The CAA’s permitting threshold of 100 or 250 short tons per year is so low that, when applied to GHGs, they would sweep hundreds of thousands of very small sources into the GHG permitting program. Recognizing that this result would be contrary to Congressional intent and unnecessarily burdensome, EPA issued a Tailoring Rule in 2010 that attempted to rationalize permitting thresholds in the GHG context by setting the PSD and Title V applicability thresholds at 100,000 short tons per year for new and existing sources. Various groups challenged the Tailoring Rule and on June 23, 2014, the Supreme Court partially vacated the rule, holding that EPA had exceeded its statutory authority in adjusting the permitting thresholds for GHG purposes. As a result of this decision, stationary sources are now subject to GHG permitting requirements only if they would have been subject to CAA permitting requirements anyway, based on emissions of other pollutants. These "anyway" sources account for the vast majority of stationary source GHG emissions in the US. EPA and state air agencies are adjusting their GHG permitting programs to comply with the Court’s decision. The current permitting threshold for GHG "anyway" sources under Title V and PSD permitting is 75,000 short tons of CO2e per year for new and existing sources, and for modifications resulting in net GHG emissions increase equal to or greater than 75,000 short tons per year. EPA is continuing to develop its GHG permitting program and strengthen the underlying legal basis.

When obtaining permits under the PSD program, including new source review (NSR) permits, sources must evaluate available emissions reductions options to determine the best available control technology (BACT) for that facility. BACT determinations are made on a case-by-case basis considering energy, environmental, and economic impacts, and other costs. Over time, technological advancements increase the degree of attainable emissions reductions. EPA has issued guidance as to relevant BACT considerations for various industry sectors and maintains a database of BACT determinations for GHG emissions and other pollutants.

Oversight of GHG Emissions

EPA’s mandatory Greenhouse Gas Reporting Rule requires reporting of GHG data and other relevant information for facilities in 41 source categories. Among other sectors, the GHG reporting program applies to power plants, petroleum and natural gas systems, refineries, and the chemicals, waste, metals, minerals, and pulp and paper industries. In general, the rule covers US sources that emit 25,000 short tons or more CO2e per year. Data is submitted electronically and EPA has processes for identifying potential errors and verifying data. EPA compiles reported GHG to create its annual GHG inventory for the US. Compliance for covered sources is mandatory, and administrative, civil or criminal penalties may apply for violations.

Several states also have implemented GHG reporting rules, and the reporting thresholds differ by state. For example, Massachusetts’ GHG reporting rule is triggered for any facility that emits more than 5,000 short tons of CO2e per year. California’s regulation requires GHG reporting for certain industrial facilities, fuel suppliers, and electricity importers that emit 10,000 short tons of CO2e per year. (Entities that emit more than 25,000 short tons of CO2e per year are also covered by the state’s cap-and-trade program.) Entities must comply with both federal and state GHG reporting requirements, if applicable.

GHG Emission Allowances


There is no GHG allowance regime at the federal level. RGGI and California operate cap-and-trade programs with associated emissions allowance regimes.

RGGI is limited to the power sector and uses an allowance system for compliance; electric power generators subject to RGGI are required to hold CO2 allowances equal to the amount of CO2 they emit in a given compliance year. Each RGGI state issues allowances in an amount defined by each state’s applicable law or regulation implementing RGGI. Collectively, these allowances comprise the annual RGGI cap. For several years, the RGGI cap existed at a level that exceeded demand. Following a program review in 2012, RGGI lowered its cap to 91 million short tons for 2014, with an annual reduction of approximately 2.5% until it reaches approximately 91 million short tons in 2020. Other mechanisms are in place to account for surplus allowances issued from 2009 to 2013. The RGGI 2015 cap is 88.7 million short tons, and the RGGI 2015 adjusted cap is 66.8 million short tons. The adjusted cap of 66.8 million reflects the total number of CO2 allowances allocated by RGGI in 2015. One unique feature of RGGI is that allowances are distributed primarily through quarterly auctions. After the cap adjustments took place, the average auction clearing price increased for RGGI allowances increased markedly, from US$2.92 in 2013 to US$4.72 in 2014. During 2015, the average auction clearing price increased 29%, rising from US$4.72 in 2014 to an average price of US$6.10 in 2015. Secondary market prices were consistent with auction prices. Through mid-2016, RGGI had conducted 32 successful allowance auctions; at the latest RGGI auction for which data is available, RGGI states sold a combined 15,089,652 allowances for total proceeds of US$68,356,123.56. RGGI also utilizes a cost containment reserve system to allocate and auction additional allowances when needed to limit price volatility.

California’s cap-and-trade program is administered by CARB as a central feature of its GHG emission reduction plan under AB 32. Under this program, which began in 2013, CARB sets an annual cap on GHGs and issues a limited number of emission allowances, each of which authorizes its holder to emit one MT CO2e. The number of available allowances is limited by the cap, and declines by approximately 3% each year. In 2013, when the program was limited to the power and large industrial sectors, the cap was set at 162.8MMT; in 2015, with the addition of transportation and heating fuels, the cap was set at 394.5MMT; in 2020 the cap will be ratcheted down to 334.2MMT. Entities that emit 25,000MT CO2e annually are obliged to surrender a certain number of compliance instruments to CARB each year, consistent with each entity’s reported emissions. Compliance instruments consist primarily of allowances, which can be purchased from CARB at quarterly auctions. In addition, up to 8% of a covered entity’s obligation can be met with CARB-certified offsets. Both allowances and offsets also may be bought and sold on the secondary market, subject to certain restrictions.

CARB exercises broad oversight over this market, much as the federal Securities and Exchange Commission supervises markets for financial instruments in the United States. Covered entities are required to disclose substantial information to CARB, including information about corporate ownership and affiliates, directors and

California’s cap-and-trade program has survived several litigation challenges to date, though one significant case challenging the auction program as an illegal tax is awaiting a decision from an intermediate appellate court. A decision is anticipated sometime in 2016.

In 2016, California’s cap-and-trade program remains linked with that of the Canadian province of Quebec, meaning that allowances issued by either jurisdiction may be used by entities in both. California conducted eight quarterly allowance auctions before linking with Quebec and the two jurisdictions have held eight joint quarterly auctions since the first one in November 2014. The Canadian province of Ontario began developing a cap-and-trade program in 2015 and it is anticipated that it will link with California in 2018. Other states in the US could develop cap-and-trade programs in response to the CPP, and if so they also may link with the California–Quebec program. See "Main Regulatory Policies" above on regional climate change programs for more detailed information.


There is no GHG allowance regime at the federal level. The registry for RGGI allowances is called the CO2 Allowance Tracking System (RGGICOATS). Each RGGI allowance has a unique serial number and is registered in RGGI-COATS, which then tracks initial ownership, transfer, and retirement of allowances. California and other linked jurisdictions utilize the Compliance Instrument Tracking System Service (CITSS) as an allowance registry. CITSS tracks the issuance, initial ownership, transfer and retirement of allowances and offsets.

Obtaining, Possessing, and Using GHG Emission Allowances

There is no GHG allowance regime at the federal level. See "GHG Emission Allowances" for a description of state and regional emissions allowances. 

Trading of GHG Emission Allowances (or Similar Emission Instruments)

There is no national GHG allowance regime or national-level emission trading system. Any qualified party can participate in RGGI allowance auctions; auction rules limit the number of allowances that associated entities may purchase in a single auction to 25% of the total allowances offered for auction. RGGI allowances also are traded on a secondary market, along with associated futures and options contracts. The RGGI-COATS registry facilitates this market by providing for allowance transfers.

California (jointly with Quebec since 2014) conducts quarterly auctions of GHG emission allowances. Both entities that are covered by California’s cap-and-trade program, as well as others that opt into the program, can participate in the auctions. In addition, a certain number of allowances are allocated directly by CARB to certain entities (principally in-state manufacturers and electric utilities), with free allocation decreasing over time. Following California’s initial auction, allowance prices stabilizing volume increased, and a robust secondary market for California carbon allowances and offsets developed. Options and futures are also traded in the secondary marketplace, with 2015 prices in the range of US$11 to US$13 per allowance. In 2016, likely due to uncertainty caused by the pending court case challenging the allowance auctions as an illegal tax and the US Supreme Court’s stay of the federal Clean Power Plan, market demand for both allowances and offsets fell significantly. Indeed, several of CARB’s allowance auctions failed to sell all of the allowances on offer. The prices for allowances thus have been at the auction floor price established by CARB’s Cap-and-Trade regulation, which was US$12.73 for the 2016 auctions. Prices for offsets on the secondary market were significantly below the auction floor price. Should the legal uncertainty be removed in 2017 and the program continue, then many market observers have projected significant price increases in the years ahead due to California’s aggressive GHG reduction goals, which goals were expanded by the adoption of SB 32 in September 2016 to 40% below 1990 levels by 2030.

CARB’s cap-and-trade program also includes numerous features intended to provide flexibility to regulated entities and to prevent excessive volatility. In addition to offsets, these include floor and ceiling prices for the allowance auctions, a cost containment reserve, and banking and borrowing provisions.

Trading Agreements

In October 2013, the International Emissions Trading Association released a trade agreement template for California allowances and offsets. Its provisions address offset invalidation, holding limits and buyer liability provisions. As of September 2015, there is no standard emissions trading agreement used for RGGI allowances.

Energy Sector Regulation

The US Energy Information Administration (EIA) compiles data and statistics on renewable and non-renewable energy production in the US. See "Main Regulatory Policies" for a discussion of emissions regulations and energy efficiency.

Crude Oil

In 2015, the US produced 3,436,537 thousand barrels of crude oil, imported 2,682,946 thousand barrels of crude oil and 265,248 thousand barrels of finished petroleum products, and consumed 7,079,331 thousand barrels of crude oil and petroleum products.

Natural Gas

In 2015, there were 32,894,683 million cubic feet of gross withdrawals of natural gas in the US, and the US consumed 27,457,587 million cubic feet of natural gas.


In 2014, the US produced 1,000,049 thousand short tons of coal and exported 97,257 thousand short tons. In 2014, total US coal consumption was about 917,732 thousand short tons of coal, divided among the following sectors:

  • Electric power: 851,602.
  • Commercial and institutional: 1,887.
  • Coke plants: 21,297.
  • Other industrial: 42,946.


In 2015, the US produced 3,343,207 pounds of uranium concentrate (U3O8) and nuclear power plants generated 797,178 thousand MWh of electricity.

In 2010, the DOE announced a series of loan guarantees to support the construction of two advanced nuclear reactors at the Alvin W Vogtle Electric Generating Plant in Georgia; the final US$1.8 billion loan closed on June 24, 2015. Significantly, the Vogtle project is the first new nuclear power plant to be licensed and begin construction in the US in over three decades.


According to EPA, total US GHG emissions in the US in 2014 were 6,870.5 MMT CO2e, representing a 1% increase from 2013 See "National Emissions, Limits, and Projects" for additional GHG emissions information. See "Oversight of GHG Emissions" for a discussion of EPA’s GHG reporting program. As discussed above, the electric generating sector is subject to GHG emissions limits through EPA permitting processes. In addition, the CPP will impose sector-wide GHG emissions limits on electric generators, if it survives pending litigation.

Energy Efficiency

Many US states also are pursuing energy efficiency strategies. 28 states have enacted Energy Efficiency Resource Standards (EERS) or other binding energy savings targets. Several other states have nonbinding programs or aspirational programs with very low-efficiency targets. State programs take a variety of approaches but often mandate or incentivize demand-side energy efficiency programs run by state and local electric utility companies. EERS vary widely but generally target incremental energy efficiency gains of 0.5% to 2.5% annually. EERS and other similar programs are driving significant investment in energy efficiency technologies, software, and services in many US states. There is no standard methodology for registering and trading instruments based on energy efficiency, and each state takes a different approach in tracking and assuring compliance, typically at the utility level. At the same time, the CPP encourages states to select energy efficiency as a compliance path, which may spur innovation and broader markets related to energy efficiency.

Other Sectors

Climate regulation in the US has focused primarily on the power and transportation sectors, although certain industrial sectors are subject to GHG reporting and permitting requirements. Permitting requirements may also apply to stationary sources in other source categories including, among others:

  • Large industrial/commercial/institutional boilers.
  • Pulp and paper.
  • Cement.
  • Iron and steel industry.
  • Refineries.
  • Nitric acid plants.
  • Landfills.

See "Main Regulatory Policies" for a discussion of applicable regulations; see "GHG Emission Permits or Approvals" for a discussion of related GHG permitting requirements. California’s climate change program is economy-wide; see "Main Regulatory Policies" for a further discussion of AB 32.

Renewable Energy and Carbon Capture

The US does not have a comprehensive national policy on renewable energy production or use. Instead, a patchwork of federal and state programs and incentives drive the renewable power sector in the US.

Twenty-nine states, plus Washington, DC, have enacted binding renewable portfolio standards (RPS). Eight other states have non-binding RPS programs. State RPS programs operate by setting renewable energy targets for each year and requiring electric utility companies to achieve that level of renewable power. As a result, RPS programs are the primary drivers for renewable energy investment in the US and are spurring significant investment in renewable energy infrastructure in many states. Renewable energy targets vary widely by state but typically are in the range of 10% to 25%. Several states have much higher targets: New York, California, and Oregon all have targets of 50%, Vermont targets 75%, and Hawaii has established a 100% target by 2045. During 2016, multiple states increased renewable energy targets established by their RPS programs or initiated efforts to do so. Collectively, these programs are expected to increase the demand for wind power by 16 gigawatts by 2024 while also driving the expansion of solar and hydrokinetic power. About 16 states also have separate, smaller targets for solar energy, often referred to as a solar carveout, which usually operate in tandem with a net metering or feed-in-tariff program. As solar energy becomes more price competitive, solar carveouts have seen lower expansion in recent years.

RPS compliance is usually managed through a system of tradeable renewable energy credits (RECs), with one REC representing one MWh of renewable power. In general, RECs are registered by state agencies and are tradeable instruments. Most state programs require compliance through the use of RECs or renewable power generated in-state, with limited exceptions, and eligible renewable resources and definitions can vary widely by state. This results in fragmented REC markets with prices varying widely by state and resource type. According to the DOE’s Green Power Network, REC prices range from about US$1 (in Texas and Washington, DC) to about US$50 (in Massachusetts and several other states). Solar RECs (SRECs) range from about US$50 to a high of nearly US$500.

In addition to mandatory RPS programs, green power programs allow US energy consumers (typically residential and commercial) to purchase renewable or green power from their utility company or independent power supplier. Energy suppliers purchase RECs on the voluntary market to meet green power demand. Voluntary REC supply is dominated by wind, though solar is increasing its market share. Prices for voluntary RECs hover around US$1/MWh, significantly lower than most RECs purchased for compliance purposes. It is estimated that more than 50% of retail customers in the US now have an option of purchasing green or low-carbon power from their utility. There were over 5.4 million green power customers in 2013, although that figure declined in 2014 to about 4.9 million customers. It is unclear if this is a continuing trend and how it relates to the rapid expansion of residential rooftop solar power in the US.

Forty-four states plus Washington, DC have implemented net metering programs, which allow grid-connected customers with renewable energy systems installed on their property to offset their electrical usage and sell excess electricity to their utility. Several states have also implemented feed-in-tariff programs that provide a higher price to consumers generating certain types of renewable energy (typically solar). Net metering and feed-in-tariff programs have aided the expansion of residential and commercial solar projects in the US, but are currently experiencing a period of uncertainty. As rooftop solar begins to provide a more significant volume of power, and as solar panel prices continue to decline, several states have moved to roll back or eliminate their net metering programs, while others are seeking new ways to properly value solar power. The debate over net metering is driven in part by utility companies who are concerned about the rapid expansion of distributed generation and by consumer groups concerned about societal cost allocation and potential increases in energy prices. As this debate continues, numerous states have expanded their net metering programs and are developing pricing mechanisms to reward solar power based on its value to the grid, factoring in time-of-service, displacement of new fossil-fuel generation and infrastructure, and environmental benefits, including GHG reduction.

At the federal level, the DOE’s loan guarantee program backs investment in renewable power, energy efficiency, and commercial climate technologies. Loans backed by the DOE have supported investment in solar, wind, geothermal, nuclear and energy storage technologies, among others. In 2013, the DOE announced the availability of US$8 billion in loan guarantees for advanced energy projects that substantially reduce GHGs and other air pollution. More recently, in 2014, the DOE announced the availability of US$4 billion in loan guarantees available for innovative renewable energy and energy efficiency projects in the US that reduce GHG emissions. On June 23, 2015, the DOE released a Supplement to Loan Guarantee Solicitation Announcement that clarifies the scope of eligible projects; applications under this program have continued through 2016.

Two federal tax credits also provide financial support for renewable energy facilities. The production tax credit (PTC) provides a tax credit for each kilowatt-hour (kWh) produced by eligible renewable power facilities. For eligible wind, geothermal, and closed-loop bioenergy projects, the PTC currently provides a 2.3 cent per kWh incentive for the first 10 years of the facility’s operation. The PTC also currently provides a lower tax credit of 1.1 cents per kWh for certain other eligible facilities, such as open-loop biomass (which utilize farm and forest wastes rather than dedicated energy crops), efficiency upgrades and capacity additions at existing hydroelectric facilities, landfill gas, and municipal solid waste energy projects. Combined with state RPS programs, the PTC has been a major driver of wind power development in the United States: between 2007 and 2014, US wind capacity nearly quadrupled. In late 2015, the US Congress extended the PTC for facilities that begin construction before December 31, 2019. The business energy investment tax credit (ITC) was significantly expanded in 2008. The ITC currently provides tax credits for capital investments in solar energy facilities (30% of expenditures), fuel cells (30% of expenditures), small wind turbines (30% of expenditures), geothermal systems (10% of expenditures), microturbines (10% of expenditures) and CHP (10% of expenditures). Credits are available for eligible energy systems placed in service on or before December 31, 2016, although some credits have caps or other restrictions. The ITC also was extended in late 2015, and now extends to the end of 2019, with a gradual step-down in credits between 2019 and 2022. More information on DOE’s loan guarantee program, the PTC and the ITC is available here.

The federal government also is working to facilitate renewable power generation on public lands through a variety of programs that are designed to streamline permitting and leasing. These programs include, but are not limited to:

  • The solar energy program established by the Department of the Interior (DOI) and the Bureau of Land Management (BLM) facilitates approval and development of solar energy generation and transmission facilities on BLM-administered lands in six western states.
  • The DOI’s Renewable Energy Coordination Offices in four western states (Arizona California, Nevada, and Wyoming) and smaller renewable energy teams in five other states (Colorado, Idaho, New Mexico, Oregon, and Utah) expedite processing of applications for new renewable energy projects on public lands.
  • The Bureau of Ocean Energy Management (BOEM) is working to identify and lease offshore wind energy areas for commercial wind energy development. On July 31, 2013, BOEM auctioned a wind energy area off the coasts of Rhode Island and Massachusetts, the first competitive lease sale in the US for an offshore wind project. An initial small-scale project is near completion, while others are in the planning stages.
  • President Obama issued a memorandum on June 7, 2013, that directs federal agencies to review and likely expand existing energy transmission corridors. The memorandum seeks to reduce the overall regulatory burden by creating a framework for collaboration between agencies.

As a result of these and other measures, along with declining prices for renewable technologies, the US renewable power sector is expanding rapidly. In 2015, the US produced 549,527 thousand MWh of renewable power at Utility Scale Facilities, as follows:

  • Conventional hydroelectric: 251,168 thousand MWh.
  • Wind: 190,927MWh.
  • Geothermal: 16,767MWh.
  • Wood and wood-derived fuels: 42,358MWh.
  • Landfill gas: 11,233MWh.
  • Biogenic municipal solid waste: 7,415MWh.
  • Other biomass: 3,184MWh.
  • Solar photovoltaic and solar thermal: 26,473MWh.

Wind Energy

Wind energy projects are subject to a range of federal, state and local environmental, land use and natural resources laws and regulations. Access to transmission also remains a significant constraint for many wind projects, since wind energy resources in the US are not always located near demand. Developing new or expanded transmission lines can increase the complexity of the above regulatory requirements. A utility-scale wind facility and related transmission facilities may require approvals under the following laws, depending on the scope and impact of the project:

  • The National Environmental Policy Act.
  • The Federal Lands Policy and Management Act.
  • The Clean Water Act.
  • The Clean Air Act.
  • The Coastal Zone Management Act.
  • The National Historic Preservation Act.
  • The Endangered Species Act.
  • The Bald and Golden Eagle Protection Act.
  • The Migratory Bird Treaty Act.
  • The Marine Mammals Protection Act.
  • Requirements imposed by the FAA and the Federal Communication Commission (FCC) pertaining to lighting, aircraft safety, signal interference, and other matters.
  • Various state and local siting, land use and environmental laws and regulations.

For projects located on federal land (notably in the West), federal land management agencies such as BLM or the United States Forest Service may act as the primary permitting authority. In some states, one or more state agencies may have permitting authority. In other cases, the primary permitting authority for a wind facility is the local planning commission, zoning board, city council or county board. Offshore wind projects also must coordinate with the US Coast Guard during construction and address any navigational hazards. The Bureau of Ocean Energy Management (BOEM) administers the offshore wind leasing process through a competitive bidding process. BOEM has held several auctions, resulting in the sale of various leases to develop offshore wind projects, primarily on the east coast. There is increasing interest in development on the west coast as well: in August 2016, BOEM issued a request for interest for a lease area off the California coast, on which a developer has expressed interest in building a 765MW floating wind energy project.

Renewable energy projects have seen significant litigation over environmental impacts and other issues. Litigation may involve local issues, such as noise, siting, and site-specific impacts, or may implicate broader state or national policies. With respect to wind energy, impacts on birds are a frequent focus of litigation. For example, in 2013, the US Fish and Wildlife Service (FWS) issued a rule that provided for programmatic permits of 30 years in duration under the Bald and Golden Eagle Protection Act, allowing take of bald or golden eagles incident to otherwise lawful activities. Under the Bald and Golden Eagle Protection Act, "take" means, among other things, to wound, kill, molest or disturb protected birds. Wind turbines have the potential to take bald eagles and other birds by direct action (i.e., death or injury due to a collision) or indirect action (i.e., disturbing nesting, migration, or other behavior). Environmentalists challenged the FWS rule, and on August 11, 2015, the US District Court for the Northern District of California issued an order invalidating the 30-year rule. As a result, for now, 30-year incidental take permits are no longer available to wind energy and other projects under the Eagle Act. Similar litigation has taken place under the Endangered Species Act and other laws. Offshore wind energy projects face similar issues arising under the Marine Mammal Protection Act, fisheries laws, and other laws aimed at the protection and development of marine resources.

Subsidies and incentive programs for wind energy are discussed in "Renewable Energy and Carbon Capture."

Solar Energy

Large, utility-scale solar power projects face many of the same regulatory challenges that arise in the context of wind energy development. Depending on the size, location, and technology, large solar energy projects may implicate a wide range of federal, state and local laws and be subject to litigation. Smaller commercial or residential solar systems, such as those commonly installed on rooftops, typically do not require major regulatory approvals. These projects must nonetheless comply with local building, zoning, land use and development regulations, and obtain any required permits. In some states, additional authorization may be required for interconnection to the grid. Further authorization may be required for feed-in tariff or net metering eligibility, or to qualify under a state’s RPS program. Subsidies and incentive programs for solar energy are discussed in "Renewable Energy and Carbon Capture."

Hydropower, Geothermal, Wave, and Tidal Energy

The Federal Energy Regulatory Commission (FERC) issues licenses for construction of new hydropower projects. During the permitting process, FERC and the applicant must assure compliance with NEPA. In many cases, permittees also must obtain authorizations under various state and federal laws, including but not limited to the Clean Water Act, the Endangered Species Act, and other laws. In some states, additional authorization may be required for hydropower resources to qualify for RPS or net metering programs.

The first commercial, grid-connected tidal energy project in the US was deployed off the coast of Eastport, Maine in July 2012. Several other wave and tidal energy projects are in developmental stages. FERC and the US Army Corps of Engineers may be involved in the permitting process for these hydrokinetic technologies, depending on location. Projects may implicate a range of laws, including but not limited to the National Environmental Policy Act; the Clean Water Act, the Coastal Zone Management Act, the Endangered Species Act, the Marine Mammals Protection Act, and various other federal, state and local laws. The Energy Policy Act of 2005 authorized BOEM to issue leases, easements and rights of way to allow for renewable energy development on the Outer Continental Shelf, including those for wave, tidal and other hydrokinetic projects. Because these projects may cause navigational hazards, coordination with the US Coast Guard is often required.

Geothermal projects are regulated by a mix of federal and state agencies, with requirements varying by state and whether the project is located on state, federal or private land. The Geothermal Steam Act of 1970 requires the DOI to establish rules and regulations for the leasing of geothermal resources on lands managed by federal agencies. These regulations are issued by the Bureau of Land Management. Existing EPA Underground Injection Control Regulations under the federal Safe Drinking Water Act define Class V injection wells to include injection wells associated with the recovery of geothermal energy.


The US has 86 waste-to-energy facilities that combust municipal solid waste. No new waste-to-energy plants have been built in the US since 1995, but some plants have expanded. Collectively, these 86 facilities have the capacity to produce 2,720 megawatts of power per year. As combustion units, waste-to-energy systems are subject to regulatory requirements that are similar to fossil-fuel-fired power plants. In some cases, those requirements may be even more stringent. The CAA imposes numerous requirements on waste-to-energy facilities, which also must comply with the Clean Water Act, the Resource Conservation and Recovery Act, and other federal, state and local laws. Permitting actions, facility expansions and new projects may implicate many of the laws listed in "Renewable Energy and Carbon Capture."

Biofuels and Biomass

In 2007, EPA established a national renewable fuel standard program that requires transportation fuel refiners to displace certain amounts of gasoline and diesel with renewable fuels such as cellulosic biofuel, biomass-based diesel, and advanced biofuel. The program established the annual renewable fuel standards, responsibilities of refiners and other fuel producers, a trading system, compliance mechanisms, and record-keeping and reporting requirements.

EPA has recently scaled back biofuel requirements to account for declining gasoline use and technical limitations related to ethanol blending and biofuel production. In November 2015, EPA finalized a goal of 18 billion gallons of renewable fuels for 2016. This was a modest increase from the agency’s June 2015 proposal, but it is still short of the 22.25 required by Congress. Still, the 18 billion gallons goal exceeds 10% of the projected gasoline production for 2016 which some US automakers advised could negatively affect the performance of cars and may violate certain warranties.

In May 2016, EPA proposed 18.8 billion gallons of renewable fuels be blended with motor fuels in 2017. This level would again exceed the 10% blend wall, though it would still fall short of the Congressionally mandated levels. A final rule is expected from EPA towards the end of 2016.

Some individual states have implemented their own regulations, such as acquisition or fuel use standards, taxes, fuel production or quality regulations, and air quality or emissions regulations. For example, California is in the process of implementing its Low Carbon Fuel Standard (LCFS). By 2020, the LCFS mandates a 10% reduction in the carbon intensity of transportation fuels that are sold, supplied or offered for sale in California. Beginning January 1, 2011, transportation fuel producers and importers had to meet specified average carbon intensity requirements for fuel in each calendar year. Carbon intensity reductions are based on reformulated gasoline mixed with 10% corn-derived ethanol and low-sulfur diesel fuel. In September 2015, CARB re-adopted the LCFS rules streamlining the application process for alternative fuel producers seeking carbon intensity credits and implementing cost containment provisions such as a cap on LCFS credit prices.

As a result of federal and state biofuels programs, the US is the world’s largest producer of biofuels.

Carbon Capture and Storage

Carbon capture storage (CCS) is a process by which CO2 from a stationary source is captured, transported and permanently stored, typically in underground injection wells. CCS has a substantial potential to reduce GHG emissions from industrial sources but has not been widely demonstrated on a commercial scale.

Several large CCS demonstration projects in the US are currently moving through the entitlement or financing process. These projects are largely supported by resources allocated by the American Recovery and Reinvestment Act of 2009, as well as a variety of federal and state incentives, including tax credits and loan guarantees.

CCS Regulatory Framework

The federal Safe Drinking Water Act requires an injection well permit for the long-term storage or geologic sequestration of CO2. Class VI injection well permits require the use of materials compatible with geological sequestration and impose certain financial responsibility requirements. Class VI wells must also comply with certain Monitoring, Reporting, and Verification (MRV) requirements as part of EPA’s GHG Mandatory Reporting Rule program. At present, no states have been delegated Class VI permitting authority by EPA.

Class II injection well permits have authorized enhanced oil recovery (EOR) activities for many years, as discussed below. Some CCS projects may rely upon Class II injection wells for both EOR and sequestration purposes, provided drinking supplies are not adversely impacted. Most states have permitting authority over Class II wells based on delegation from EPA. Use of a Class-II well does not require EPA approval of an MRV program, although facilities may choose to opt into EPA’s MRV program.

On December 1, 2010, EPA published its final rule concerning the expansion of its GHG reporting rule to include facilities that inject and store CO2 for geologic sequestration or enhanced oil and gas recovery. CCS has also begun to play an important role as a control technology for GHG regulations for power plants. The CPP includes stringent CO2 emissions standards for new coal-fired power plants that will likely require the use of CCS.

In January 2014, the EPA issued a final rule excluding CO2 streams in CCS projects from classification as a hazardous substance under the Resource Conservation and Recovery Act, provided that the streams are injected into Class VI wells and not mixed or co-injected with any hazardous wastes. CCS projects are potentially affected by several other regulatory programs. For instance, NEPA and state equivalents may present regulatory hurdles by requiring an environmental review of project impacts. State and local agencies may also impose permitting requirements on CCS projects.

Co-Benefits of CO2: Enhanced Oil Recovery

EOR has been used successfully since the early 1970s to recover additional oil from existing sources. The DOE estimates that EOR may allow the extraction of 30% to 60% of a reservoir’s original oil compared with 20% to 40% extracted by primary and secondary recovery. The EIA estimates that domestic use of CO2 for EOR can produce over 4 billion additional barrels of oil between 2011 and 2035. DOE estimates that CO2 EOR, over 30 years, for the US could potentially spur US$10 trillion in economic development, create 2.5 million jobs, and drive a 30% to 40% reduction in imported oil.

CCS has long been touted as a potentially critical means for reducing GHG emissions from carbon-intense industrial sources. In October 2014, Canada began operating the first commercial-scale coal-fired power plant fitted with CCS technology. A portion of the CO2 captured by the plant will be pumped underground and sold to oil companies for use in priming oil fields. The Canadian plant received US$240 million Canadian in subsidies from the Canadian federal government.

In the United States, the Department of Energy has awarded US$7 billion in funding since 2008 to develop clean coal technologies, including US$68 million in funding announced in July 2016 for CCS research. Similar bills introduced in the House and Senate in July 2016 could drive development by increasing CCS tax credits from US$10 per ton to US$35 per ton.

However, high costs, complex regulatory schemes and the low price of natural gas have hindered the widespread development of CCS projects. Only about 16 large-scale CCS projects are operating globally. In the future, lower technology costs and the development of multiple revenue streams from the CO2 associated with CCS projects, particularly using captured CO2 for EOR, may help spur CCS development.

Climate Matters in Transactions

Entities must consider a range of climate issues when undertaking M&A transactions. Risks generally fall into three categories: regulatory, economic, and operational risk related to climate change impacts. Some matters also present M&A opportunities, such as incentives related to renewable energy. Matters to consider include:

  • GHG reporting and permitting obligations for certain sectors.
  • EPA regulation of GHG emissions and related costs for higher-emitting industries.
  • Regulatory uncertainty resulting from a lack of a comprehensive national climate change program.
  • Regulatory costs associated with assuring compliance with a plethora of federal, state and local climate change, energy efficiency, and renewable energy programs.
  • Litigation exposure to claims based upon alleged climate impact of corporate operations or of climate changes on corporate operations.
  • Direct and indirect effects of higher energy costs.
  • Financial disclosure and compliance obligations under Securities and Exchange Commission rules and state laws.
  • Adherence to Equator Principles, if applicable, which include requirements for climate impacts.
  • Impacts on coastlines, ports and other infrastructure related to increased storm intensity and sea level rise.
  • Impacts on natural resources and commodities related to climate change, such as water supplies, fisheries, forestry products, and crops.
  • Global economic and security risks related to potentially destabilizing impacts of climate change in certain regions.
  • Market opportunities related to renewable power, REC and offset trading, GHG mitigation, and energy efficiency.

Updates and Trends

While the federal CPP is the most high-profile development in US climate change regulation, the federal program relies heavily on states to develop and implement their own GHG mitigation strategies. These state-level policymaking processes will build political and institutional momentum, and will likely yield at least some substantive, subnational GHG reductions policies even if the CPP is defeated in whole or part by litigation, or modified by subsequent administrations.

Independently of the CPP, there are signs that political support for state and regional GHG regulation is growing. California has recently announced more aggressive long-term goals for its program. Washington State Governor Inslee also has proposed an aggressive, economy-wide cap-and-trade program that could one day be linked with the California program. In the northeast, RGGI has adopted more aggressive goals for its cap-and-trade program, and Pennsylvania has expressed interest in joining. Dealmakers should follow developments related to the federal CPP, but should also monitor state activities for the next generation of climate change regulation. It is widely anticipated that these state and regional programs will continue to drive economic activity in energy efficiency, renewable power, energy storage, transmission, emissions trading, and other related markets.

©2017. Published in Environment & Climate Change Regulation, 2017, by Getting the Deal Through. Reproduced with permission. All rights reserved.