Tag: energy

The Inflation Reduction Act: How Do Tribal Communities Benefit?

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA”), ushering in substantial changes for tax law, climate resilience, healthcare, and more in the United States. According to the Biden administration’s press release, the new $750 billion legislation aims to lower everyday costs for families, insist that corporations pay their fair share, and combat the climate crisis. During the signing ceremony, President Biden stated, “With this law, the American people won and the special interests lost […] For a while people doubted whether any of that was going to happen, but we are in a season of substance.”

Notably, the legislation provides significant provisions for tribal communities and the Bureau of Indian Affairs. Once the funding is appropriated by Congress, it will be directed toward drought mitigation programs, fish hatcheries, modernization of electric systems, and more for Native communities, including ones in Alaska and Hawaii.

How the Inflation Reduction Act of 2022 Supports the Environment and Tribal Communities

The Inflation Reduction Act of 2022 contains an array of provisions, including the reduction of drug prices, the lowering of energy costs, and, notably, federal infrastructure investments that benefit Native communities. Andrew M. VanderJack and Laura Jones, Co-Coordinators of Van Ness Feldman’s Native Affairs Practice, highlight the most significant facets of the bill: “This legislation provides some opportunities specifically for tribes and tribal entities, including programs related to climate resiliency and adaptation, electrification, and drought relief. For example, the Emergency Drought Relief program for Tribes extends direct financial assistance to tribal governments to address drinking water shortages and to mitigate the loss of tribal trust resources.”

Pilar Thomas, Partner in Quarles & Brady’s Energy, Environment & Natural Resources Practice Group, expanded on the most significant inclusions for Tribes: “[…] the creation of a Direct Pay tax credit payment program that allows Tribes to receive a payment equal to the clean energy technology tax credits – especially for solar, wind, storage, geothermal and EV charging stations; […] direct funding for electrification and climate resiliency through DOI and USDA; […] access to the greenhouse gas reduction fund, environmental and climate justice grants; and expanded energy efficiency tax benefits and rebates for tribes and tribal members.”

“Tribal governments are also eligible to apply for other programs such as the Clean Vehicle Credit program, the Energy Efficient Commercial Buildings Deduction, and the State and Private Forestry Conservation Programs,” noted Mr. VanderJack and Ms. Jones.

How the 2022 Inflation Reduction Act Has Been Received by Tribal Communities

The 2022 Inflation Reduction Act has received a warm reception from groups such as the National Indian Health Board and Native Organizers Alliance, who laud the bill’s potential to improve environmental, medical, and economic conditions for tribal communities, some of whom still lack access to electricity or clean water. The increase in funding will allow tribes to use green energy technology to increase climate resilience and decrease individual energy costs, while reducing the effects of environmental racism with risk assessments for drinking water and climate hazards. These infrastructural changes will stimulate economic development by creating new jobs. “With critical investments in the Inflation Reduction Act, we’re making sure the federal government steps up to support Native-driven climate resilience, advance tribal energy development, and fulfill its trust responsibility to Native communities,” said Senator and Senate Committee on Indian Affairs Chairman Brian Schatz.

“This legislation will result in hundreds of millions of funding available for Tribes, and non-profits that work with tribes and tribal communities to support the clean energy transition for tribal communities, reduce energy costs for tribal members, and create jobs,” said Ms. Thomas of Quarles & Brady. “The IRA will provide a substantial down payment for every tribe to take advantage of clean energy technologies, energy efficiency and energy savings, and climate resilient solutions for their communities and tribal members individually.  The new projects, technology implementation and economic development opportunities are substantial and will create long term community and economic development sustainable improvements in tribal communities.”

Some groups feel that the new legislation does not go far enough. In an open letter to President Biden, Senate Majority Leader Chuck Schumer, and House Speaker Nancy Pelosi, Indigenous-led advocacy organization NDN Collective argued that Congress’ hesitance to fully reject fossil fuels undermines the stated goals of addressing climate change, a misstep that could disproportionately affect tribal communities at the frontlines of the environmental crisis. “We believe that moving away from investments in the fossil fuel and other extractive industries and reallocating the funding to further research and development will help us find the solutions we need for true decarbonization and large-scale equitable carbon emissions reductions,” the collective stated. “We are already aware of innovative, Indigenous-led solutions that just need the proper funding and support to be scaled and replicated.”

Challenges in Getting the 2022 Inflation Reduction Act Passed

Up to this point, the Inflation Reduction Act has faced significant challenges in Congress. The legislation is the product of extensive compromise over the Build Back Better Act within the Democratic party. The Build Back Better Bill was initially estimated to cost over $3 trillion, and ultimately, the Inflation Reduction Act was passed with a budget of $750 billion. Senator Joe Manchin of West Virginia held back his support of the bill until late July, and Republicans successfully blocked an aspect of the bill that would have capped the price of insulin for Americans with private health insurance. When presented to Congress, the vote was split by party lines with every Republican voting against the bill. Biden has criticized Republicans for this decision, saying at the signing of the Inflation Reduction Act, “every single Republican in the Congress sided with the special interests in this vote — every single one.”

Challenges for tribal governments remain as well, specifically concerning the IRA’s implementation. “Despite the incredible opportunity for tribes, major barriers remain including tribal internal capacity and capabilities, [and] federal regulatory hurdles (such as BIA leasing and easement approvals),” said Ms. Thomas.

“[…] Navigating the complexities of each program and actually obtaining funding is always the challenge,” said Mr. VanderJack and Ms. Jones of Van Ness Feldman. “Tribes and tribal entities should engage directly, whenever possible, with the grant funding agencies to make sure proposals are tailored to fit both program requirements and community needs.”

Early Assessment of How the IRA will Impact Tribal Communities

The Inflation Reduction Act, ultimately, provides meaningful resources and investments for tribal communities in a variety of ways. While the provisions are not as significant as COVID-19 relief and infrastructure funding that tribal governments have received in previous years, the new legislation is nonetheless beneficial. “While the federal grant funding is relatively small, the potential major impact is the ability to access funding through tax credit payments and rebates,” said Ms. Thomas. “This mechanism is critical as it is simplifies tribes’ access to funding (rather than, for example, seeking to obtain funding through the competitive grant programs).”

Article By Chandler Ford, Casey Karthaus, Crissonna Tennison, and Shelby Garrett of The National Law Review / The National Law Forum LLC.

For more tribal law / indigenous peoples legal news, click here to visit the National Law Review.

Copyright ©2022 National Law Forum, LLC

CERCLA PFAS Designation Major Step Forward

On January 10, 2022, the EPA submitted a plan for a PFAS Superfund designation to the White House Office of Management and Budget (OMB) when it indicated an intent to designate two legacy PFAS – PFOA and PFOS – as “hazardous substances” under the Comprehensive Environmental Response, Compensation & Liability Act (CERCLA, also known as the Superfund law). The EPA previously stated its intent to make the proposed designation by March 2022 when it introduced its PFAS Roadmap in October 2021. Under the Roadmap, the EPA planned to issue its proposed CERCLA designation in the spring of 2022. On Friday, a CERCLA PFAS designation took a significant step forward when the OMB approved the EPA’s plan for PFOA and PFOS designation. This step opens the door for the EPA to put forth its proposed designation of PFOA and PFOS under CERCLA and engage in the required public comment period.

Any PFAS designation will have enormous financial impacts on companies with any sort of legacy or current PFOA and PFOS pollution concerns. Corporations, insurers, investment firms, and private equity alike must pay attention to this change in law when considering risk issues.

Opposition to CERCLA Designation

Since the EPA’s submission of its intent to designate PFOA and PFOS as hazardous substance to the OMB, the EPA has been met with industry pushback on the proposal. Three industries met with the OMB earlier in 2022 to explain the enormity of regulatory and cleanup costs that the industries would face with a CERCLA designation of PFOA and PFOS – water utilities, waste management companies, and the International Liquid Terminals Association. These industries in particular are concerned about bearing the burden of enormous cleanup costs for pollution that third parties are responsible for. Industries are urging the OMB and EPA to consider other ways to achieve regulatory and remediation goals aside from a CERCLA designation.

During an April 5, 2022 meeting of the Environmental Council of the States (ECOS), several states also expressed concerns regarding the impact that a CERCLA designation for PFAS types would have in their states and on their constituent companies. The state environmental leaders discussed with EPA representatives how the EPA would view companies in their states that fall into categories such as waste management and water utilities, who are already facing uphill battles in disposing of waste or sludge that contains PFAS.

Realizing that the EPA is likely set on its path to designate at least two PFAS as “hazardous substances”, though, industries are asking the EPA to consider PFAS CERCLA exemptions for certain industries, which would exempt certain industry types from liability under CERCLA. Industries are also pushing the EPA, OMB and the U.S. Chamber of Commerce to conduct a robust risk analysis to fully vet the impact that the designation will have on companies financially. The EPA is statutorily required to conduct a risk analysis as part of its CERCLA designation process, so it is likely that the EPA’s delay in issuing a proposed hazardous substance designation until it feels that adequate time has passed for its designation to survive the likely legal challenges that will likely follow the designation.

CERCLA PFAS Designation: Impact On Businesses

Once a substance is classified as a “hazardous substance” under CERCLA, the EPA can force parties that it deems to be polluters to either cleanup the polluted site or reimburse the EPA for the full remediation of the contaminated site. Without a PFAS Superfund designation, the EPA can merely attribute blame to parties that it feels contributed to the pollution, but it has no authority to force the parties to remediate or pay costs. The designation also triggers considerable reporting requirements for companies. Currently, those reporting requirements with respect to PFAS do not exist, but they would apply to industries well beyond just PFAS manufacturers.

The downstream effects of a PFOA and PFOS designation would be massive. Companies that utilized PFOA and PFOS in their industrial or manufacturing processes and sent the PFOA/PFOS waste to landfills or otherwise discharged the chemicals into the environment will be at immediate risk for enforcement action by the EPA given the EPA’s stated intent to hold all PFAS polluters of any kind accountable. Waste management companies should be especially concerned given the large swaths of land that are utilized for landfills and the likely PFAS pollution that can be found in most landfills due to the chemicals’ prevalence in consumer goods. These site owners may be the first targeted when the PFOA/PFOS designation is made, which will lead to lawsuits filed against any company that sent waste to the landfills for contribution to the cost of cleanup that the waste management company or its insured will bear.

Also of concern to companies are the re-opener possibilities that a CERCLA designation would result in. Sites that are or were previously designated as Superfund sites will be subject to additional review for PFOA/PFOS concerns. Sites found to have PFOA/PFOS pollution can be re-opened by the EPA for investigation and remediation cost attribution to parties that the EPA finds to be responsible parties for the pollution. Whether through direct enforcement action, re-opener remediation actions, or lawsuits for contribution, the costs for site cleanup could amount to tens of millions of dollars, of course depending on the scope of pollution.

Conclusion

Now more than ever, the EPA is clearly on a path to regulate PFAS contamination in the country’s water, land and air. The EPA has also for the first time publicly stated when they expect such regulations to be enacted. These regulations will require states to act, as well (and some states may still enact stronger regulations than the EPA). Both the federal and the state level regulations will impact businesses and industries of many kinds, even if their contribution to drinking water contamination issues may seem on the surface to be de minimus. In states that already have PFAS drinking water standards enacted, businesses and property owners have already seen local environmental agencies scrutinize possible sources of PFAS pollution much more closely than ever before, which has resulted in unexpected costs. Beyond drinking water, though, the EPA PFAS plan shows the EPA’s desire to take regulatory action well beyond just drinking water, and companies absolutely must begin preparing now for regulatory actions that will have significant financial impacts down the road.

Article By John Gardella of CMBG3 Law

For more energy and environmental legal news, click here to visit the National Law Review.

©2022 CMBG3 Law, LLC. All rights reserved.

Relief Arrives for Renewable Energy Industry – Inflation Reduction Act of 2022

On August 12, 2022, Congress passed the Inflation Reduction Act of 2022 (“Act” or “IRA”), a $400 billion legislative package containing significant tax and other governmental incentives for the energy industry, in particular the renewable energy industry. The bill will have an immediate impact on the wind and solar industries, along with other clean energy projects and businesses.

SUMMARY

The IRA is a slimmed down substitute for the Build Back Better bill resulting from a compromise with Senator Joe Manchin (D-WV), whose support was necessary for the bill to pass the Senate.

The IRA comes as welcome news to the renewable energy industry as important tax incentives for wind, solar and other renewable energy resources are set to expire or wind down. Existing law also did not provide any federal tax incentives for the rapidly growing stand-alone energy storage and clean hydrogen industries.

The IRA fixes that, and more. The Act extends the investment tax credit (ITC) for solar, geothermal, biogas, fuel cells, waste energy recovery, combined heat and power, small wind property, and microturbine and microgrid property for projects beginning construction before January 1, 2025. It also extends the production tax credit (PTC) for wind, biomass, geothermal, solar (which previously expired at the end of 2005), landfill gas, municipal solid waste, qualified hydropower, and marine and hydrokinetic resources for projects beginning construction before January 1, 2025. The IRA also allows taxpayers to include their interconnection costs as part of their eligible basis for the ITC.

The Act now allows the ITC to be taken for stand-alone energy storage (previously storage was only allowed an ITC if it was part of another project, e.g., solar). Other technologies are also benefitted from the IRA, including carbon capture and sequestration (CCS) (tax credit extended and modified), clean hydrogen (a new credit of up to $3.00 per kilogram of clean hydrogen produced), nuclear power (a new credit of up to 1.5c/kWh) and biofuel (existing credit extended).

The ITC and PTC now come with strings attached. To qualify for the restored 30% ITC and the 2.6c/kWh PTC (adjusted for inflation), projects must pay prevailing wages during construction and the first five years (in the case of the ITC) and 10 years (in the case of the PTC) of operation, while also meeting registered apprenticeship requirements. Projects that fail to satisfy the prevailing wage and apprenticeship requirements will only receive an ITC of 6% or a PTC of .3c/kWh (adjusted for inflation). The prevailing wage and apprenticeship requirements apply to employees of contractors and subcontractors as well as the company. These requirements are effective for projects that begin construction 60 days after the IRS issues additional guidance on this issue. Certain exceptions apply, including for certain small (less than 1 MW) facilities.

On the flip side, the Act includes enhancements that, in the case of the ITC, can increase the credit percentage if a project satisfies certain additional criteria. Bonuses are available for projects that (1) satisfy certain U.S. domestic content requirements (10%) or (2) are located in an “energy community” (10%) or an “environmental justice” area (10% or 20%). An “energy community” is defined as a brownfield site, an area which has or had significant employment related to oil, gas, or coal activities, or a census tract or any adjoining tract in which a coal mine closed after December 31, 1999, or in which a coal-fired electric power plant was retired after December 31, 2009. An “environmental justice” area is a low-income community or Native American land (defined in the Energy Policy Act of 1992) (10%) or a low-income residential building or qualified low-income economic benefit project (20%).

The Act also creates two new methods for monetizing the ITC, PTC, and certain other credits. Tax-exempt organizations will be permitted to elect a “direct pay” option in lieu of a tax credit. In a dramatic change that may have substantial impacts on renewable project finance, the Act permits most taxpayers to transfer the ITC, PTC, and certain other tax credits for cash.

For the first time, the Act includes a tax credit, known as the Advanced Manufacturing Production Credit, for companies manufacturing clean energy equipment in the U.S. such as PV cells, PV wafers, solar grade polysilicon, solar modules, wind energy components, torque tubes, structural fasteners, electrode active materials, battery cells, battery modules, and critical minerals.

The Act also contains major tax incentives, in the form of credits and enhanced deductions to spur electric and hydrogen-fueled vehicles, alternative fuel refueling stations, nuclear power, energy efficiency, biofuels, carbon sequestration and clean hydrogen. Additional grants are available for interregional and offshore wind and electricity transmission projects, including for interconnecting offshore wind farms to the transmission grid.

Additional detail regarding these provisions follow below.

KEY ENERGY PROVISIONS OF THE INFLATION REDUCTION ACT OF 2022

Investment Tax Credit (ITC)

The ITC is extended for projects beginning construction prior to January 1, 2025. The ITC starts at a base rate of 6%. The ITC increases to 30% if a project (1) pays prevailing wages during the construction phase and for the first five years of operation and (2) meets registered apprenticeship requirements. The ITC applies to solar, fuel cells, waste energy recovery, geothermal, combined heat and power, and small wind property, and is now expanded to include stand-alone energy storage projects (including thermal energy storage), qualified biogas projects such as landfill gas, electrochromic glass, and microgrid controllers. For microturbine property the base rate is 2%, which increases to 10% if the prevailing wage and apprenticeship requirements are met.

Projects under one megawatt (AC) and projects that begin construction prior to 60 days after the Secretary of the Treasury publishes guidance on the wage and registered apprenticeship requirements do not have to meet the prevailing wage and apprenticeship requirements to qualify for the 30% ITC.

PREVAILING WAGE REQUIREMENT

The new prevailing wage requirement is intended to ensure that laborers and mechanics employed by the project company and its contractors and subcontractors for the construction, alteration or repair of qualifying projects are paid no less than prevailing rates for similar work in the locality where the facility is located. The prevailing rate will be determined by the most recent rates published by the U. S. Secretary of Labor. Prevailing wages for the area must be paid during construction and for the first five years of operation for repairs or alterations once the project is placed in service. Failure to satisfy the standard will result in a significant penalty, including an 80% reduction in the ITC (i.e., an ITC of 6%), remittance of the wage shortfall to the underpaid employee(s) and a $5,000 penalty per failure. For intentional disregard of the requirement the penalty increases to three times the wage shortfall and $10,000 penalty per employee.

The prevailing wage requirement takes effect for projects that begin construction after December 31, 2022, but not before 60 days after the Secretary publishes its guidance. Projects under 1 MW (AC) are exempt from the requirement.

APPRENTICESHIP REQUIREMENT

For projects with four or more employees, work on the project by contractors and subcontractors must be performed by qualified apprentices for the “applicable percentage” of the total number of labor hours. A qualified apprentice is an employee who participates in an apprenticeship program under the National Apprenticeship Act. The applicable percentage of labor hours phases in and is equal to 10% of the total labor hours for projects that begin construction in 2022, 12.5% for projects beginning construction in 2023, and 15% thereafter. Similar penalties to the prevailing wage penalties apply for failure to satisfy the apprenticeship requirement. A “good faith” exception applies where an employer attempts but cannot find apprentices in the project’s locality.

The apprenticeship requirement takes effect for projects that begin construction after December 31, 2022, but not before 60 days after the Secretary publishes its relevant guidance. Projects under 1 MW (AC) are exempt from the requirement.

Credit Enhancements

Domestic Content. Assuming a project meets the prevailing wage and apprenticeship requirements, a qualifying project can earn a 10% ITC bonus (i.e., bringing the ITC to 40%), if it satisfies the domestic content requirement. To satisfy the domestic content requirement a project must use 100% U.S. steel and iron, and an “adjusted percentage” of the total costs of its manufactured components with products that are mined, produced or manufactured in the U.S. The applicable percentage for projects other than for offshore wind facilities initially is set at 40%, increasing to 45% in 2025, 50% in 2026, and 55% in 2027. For offshore wind facilities the adjusted percentage initially is 20%, and phases up to 27.5% in 2025, 35% in 2026, 45% in 2027, and 55% in 2028 and after. The initial domestic content bonus for projects failing to meet the prevailing wage and apprenticeship requirement is 2%, which percentage similarly phases up.

Two exceptions exist to the domestic content requirement: (1) if the facility is less than 1 MW (AC) and (2) if satisfying the requirement will increase the overall cost of construction by more than 25 percent, or if the relevant products are not produced in the U.S. in sufficient and reasonably available quantities or quality. Under these circumstances, the unavailability of the product is counted 100% against the adjusted percentage, that is, the adjusted percentage is calculated as if 100% U.S. content was supplied for the unavailable items.

The domestic content bonus is only available for projects placed in service after December 31, 2022.

Energy Community Bonus. A project can earn an additional 10% ITC bonus if it is built in an energy community. An energy community is defined as (a) a brownfield site (as defined under CERCLA), (b) an area that has or had significant employment related to the coal, oil, or gas industry and has an unemployment rate at or above the national average, or (c) a census tract or adjoining tract in which a coal mine closed after December 31, 1999 or a coal-fired electric power plant was retired after December 31, 2009.

The Energy Community Bonus is only available for projects placed in service after January 1, 2023.

Environmental Justice. An additional 10% and, in some cases, 20% ITC bonus, is available for solar and wind projects of 5 MW AC or less where the project is located in, or services, a low-income community. The environmental justice bonus is limited to a maximum of 1.8 gigawatts of solar and wind capacity in each of calendar years 2023 and 2024, for which a project must receive an allocation from the U.S. Treasury Secretary. The 10% bonus is for projects located in a low-income community or on Native American land (defined in the Energy Policy Act of 1992). The 20% bonus is available for projects that are part of a qualified low-income residential building project or a qualified low-income economic benefit project. A qualified low-income residential project is a residential rental building that participates in a housing program such as those covered under the Violence Against Women Act of 1994, a housing assistance program administered by the Department of Agriculture under the Housing Act of 1949, a housing program administered under the Native American Housing Assistance and Self-Determination Act of 1996, or similar affordable housing programs. A qualified low-income economic benefit project is one where at least 50% of the households have income at less than 200% of the poverty line or at less than 80% of the area’s median gross income.

Storage projects installed in connection with a solar project also qualify for the environmental justice bonus, but not stand-alone storage projects. A project receiving an allocation for the environmental justice credit must be placed in service within four years of the date it receives the allocation.

Stand-Alone Storage. The Act now provides a tax credit for stand-alone energy storage projects. To qualify, the storage project must be capable of receiving, storing and delivering electrical energy and have a nameplate capacity of at least 5 kWh. Thermal storage projects and hydrogen storage projects qualify under the new provision. Like the ITC for other technologies, the base ITC for stand-alone storage is 6%, and increases to 30% for projects that satisfy the prevailing wage and apprenticeship requirements or if they are placed into service prior to 60 days after the Treasury Secretary issues guidance on prevailing wage and apprenticeship standards.

Interconnection Equipment. Qualifying projects under 5 MW (AC) now may claim an ITC on their interconnection costs. The credit applies even if the interconnection facilities are owned by the interconnecting utility, so long as they were paid for by the taxpayer. This is not a stand-alone tax credit, but rather an additional cost added to a project’s basis eligible for the ITC.

Production Tax Credit (PTC)

The Act extends the production tax credit (PTC) for projects beginning construction before January 1, 2025. The PTC is set at an initial Base Rate of .3c/kwh. Like the ITC, the credit increases to 1.5c/kwh for projects satisfying the prevailing wage and apprenticeship requirements. The 1.5 c/kWh, with the inflationary adjustment provided for the PTC, brings the PTC up to 2.6c/kWh in 2022. In addition to wind projects, the PTC is available to solar, closed-loop and open-loop biomass, geothermal, landfill gas, municipal solid waste, qualifying hydropower, and marine and hydrokinetic facilities. Thus, solar projects may now choose either the PTC or the ITC. They cannot receive both.

CREDIT ENHANCEMENTS

Like the ITC, a project can receive an enhanced PTC similar in degree to those under the ITC for satisfying the domestic content, energy community and/or environmental justice requirements. For projects meeting the prevailing wage and apprenticeship requirements the increase for each applicable bonus is generally 10% of the underlying credit and, for projects failing to satisfy those requirements, 2%.

Clean Electricity Investment Tax Credit

The Act creates a new clean electricity tax credit (ITC and PTC) that replaces the existing ITC and PTC once they phase out at the end of 2024. The successor ITC/PTC is technology neutral. Any project producing electricity can qualify for the tax credit if its greenhouse gas emissions rate is not greater than zero. The successor ITC is 30% and the PTC is 1.5c/kWh, escalated annually with inflation. The Clean Energy ITC/PTC will phase out the later of 2032 or when emission targets are achieved (i.e., the electric power sector emits 75% less carbon than 2022 levels). Once the target is reached, facilities will be able to claim a credit at 100% value in the first year, then 75%, then 50%, and then 0%.

Clean Hydrogen Production Credit

This Act for the first time provides a tax credit for qualifying clean hydrogen projects. The credit is available for clean hydrogen produced at a qualifying facility during the facility’s first 10 years of operation. The base credit amount is $0.60 per kilogram (kg) times the “applicable percentage,” adjusted annually for inflation. For projects meeting the prevailing wage and apprenticeship requirements the credit amount is five times that base amount, or $3.00/kg times the applicable percentage, adjusted annually for inflation.

The applicable percentage for hydrogen projects achieving a lifecycle greenhouse gas emissions rate of less than 0.45 kilograms of carbon dioxide equivalent (CO2e) per kg is 100%. The applicable percentage falls to 33.4% for hydrogen projects with an emissions rate between .45kg and 1.5kg, and to 25% for hydrogen projects with an emissions rate between 1.5 kg and 2.5 kg. For hydrogen projects with a lifecycle greenhouse gas emissions rate between 4 kg and 2.5 kg of CO2e per kg, the applicable percentage is 20%.

To qualify for the credit, the facility must begin construction before January 1, 2033. Facilities existing before January 1, 2023 can qualify for a credit based on the date that modifications to their facility required to produce clean hydrogen are placed into service. Taxpayers may also claim the PTC for electricity produced from renewable resources by the taxpayer if the electricity is used at a clean hydrogen facility to produce qualified clean hydrogen. The Direct Pay option, discussed below, is available for clean hydrogen projects.

Taxpayers can elect to claim the ITC in lieu of the clean hydrogen production credit. However, taxpayers claiming the clean hydrogen credit cannot also claim a tax credit for carbon capture under Section 45Q, and vice versa.

Carbon Capture and Sequestration (CCS) Credit

Under prior law, industrial carbon capture or direct air capture (DAC) facilities that began construction by December 31, 2025, could qualify for the Section 45Q tax credit for carbon oxide sequestration. This credit could be claimed for carbon oxide captured during the 12-year period following the facility being placed in service. The per metric ton tax credit for geologically sequestered carbon oxide was set to increase to $50 per ton by 2026 ($35 per ton for carbon oxide that is reused, such as for enhanced oil recovery) and adjusted for inflation thereafter.

The Act extends the deadline for construction to January 1, 2033 and increases the credit amount. The base credit amount for CCS is $17 per metric ton for carbon oxide that is captured and geologically sequestered, and $12 per metric ton for carbon oxide that is reused. For facilities that meet the prevailing wage and apprenticeship requirements during construction and for the first 12 years of operation, the credit amounts are $85 per ton and $60 per ton, respectively.

The credit amount for carbon oxide captured using DAC and geologically sequestered is also increased under the Act to a base rate of $36 per metric ton, and to $180 per metric ton for projects that meet prevailing wage and apprenticeship requirements. The rates are indexed for inflation beginning in 2026.

The Act reduces the minimum plant size required to qualify for the credit:  from 100,000 to 1,000 tons per year for DAC; from 500,000 to 18,750 metric tons per year for electric generating facilities paired with qualifying CCS equipment, and from 25,000 to 12,500 metric tons per year for any other facility. A CCS project paired with an electric generating unit will be required to capture at least 75% of unit (not facility) CO2 production.

Advanced Energy Project Credit

The Act provides a 30% credit for investments in projects that re-equip, expend, or establish certain domestic manufacturing or industrial facilities to support the production or recycling of renewable energy property. Examples of such facilities include those producing or recycling components for:

  • Energy storage systems and components;
  • Grid modernization equipment or components;
  • Equipment designed to remove, use, or sequester carbon oxide emissions;
  • Equipment designed to refine, electrolyze, or blend any fuel, chemical, or product which is renewable or low-carbon and low-emission;
  • Property designed to produce energy conservation technologies (residential, commercial and industrial);
  • Electric or fuel-cell vehicles, including for charging and refueling infrastructure;
  • Hybrid vehicles weighing less than 14,000 pounds and associated technologies, components, or materials;
  • Re-equipping industrial and manufacturing facilities to reduce their greenhouse gas emissions by at least 20%;
  • Re-equipping, expanding, or establishing an industrial facility for the processing, refining or recycling of critical materials.

Projects not satisfying the prevailing wage and apprenticeship requirements will only receive the base ITC credit of 6%.

The Act makes $10 billion available for qualifying advanced energy projects. Of that amount, at least $4 billion must be allocated to projects located in energy communities. The Treasury Secretary will establish a program to award credits to qualifying advanced energy projects. Applicants awarded credits will have two years to place the property in service. The provision goes into effect on January 1, 2023.

Advanced Manufacturing Production

The Act creates a new production tax credit that can be claimed for the domestic production and sale of qualifying solar and wind components, such as inverters, battery components and critical minerals needed to produce these components.

Credits for solar components include:

  • for thin film photovoltaic cell or crystalline photovoltaic cell, 4 cents per DC watt of capacity;
  • for photovoltaic wafers, $12 per square meter;
  • for solar grade polysilicon, $3 per kilogram;
  • for polymeric backsheet, 40 cents per square meter; and
  • for solar modules, 7 cents per DC watt of capacity.

For wind energy components, if the component is an offshore wind vessel, the credit is equal to 10% of the sales price of the vessel. Otherwise, the credits for various wind components vary as set forth below, which amount is multiplied by the total rated capacity of the completed wind turbine on a per watt basis for which the component is designed.

The applicable amounts for wind energy components are:

  • 2 cents for blades
  • 5 cents for nacelles
  • 3 cents for towers
  • 2 cents for fixed platform offshore wind foundations
  • 4 cents for floating platform offshore wind foundations
  • for torque tubes and longitudinal purlin, $0.87 per kg
  • for structural fasteners, $2.28 per kg
  • for inverters, the credit is an amount multiplied by the inverter’s AC capacity, with different types of inverters eligible for specified credit amounts ranging from 1.5 cents to 11 cents per watt
  • for electrode active materials, the credit is 10% of the production cost
  • for battery cells the credit is $35 per kilowatt hour of battery cell capacity. Battery modules qualify for a credit of $10 per kilowatt hour of capacity (or $45 in the case of a battery module which does not use battery cells).

A 10% credit is also available for the production of critical minerals. Critical minerals include aluminum, antimony, barite, beryllium, cerium, cesium, chromium, cobalt, dysprosium, europium, fluorspar, gadolinium, germanium, graphite, indium, lithium, manganese, neodymium, nickel, niobium, tellurium, tin, tungsten, vanadium and yttrium.

For purposes of the credits for battery cells and modules, to qualify the capacity-to-power ratio cannot exceed 100:1. The term ‘capacity-to-power ratio’ means the ratio of the capacity of the cell or module to the maximum discharge amount of the cell or module.

The advanced manufacturing credit phases out for components sold after December 31, 2029. Components sold in 2030 are eligible for 75% of the full credit amount. Components sold in 2031 and 2032 are eligible for 50% and 25% of the full credit amount, respectively. No credit is available for components sold after December 31, 2032. The phase-out does not apply to the production of critical minerals.

DIRECT PAY

The Act contains a valuable cash payment option that allows certain organizations to treat certain tax credit amounts including, among others, the ITC, PTC, clean hydrogen, and carbon capture credits, as payments of tax and then receive a refund for that tax that is deemed paid. Under the so-called “direct pay” option, in lieu of receiving a tax credit, an eligible entity will be treated as if it had paid taxes in the amount of the credit, for which it can then receive a cash refund. Entities eligible for the direct pay option include tax-exempt organizations, state and local governments, Indian tribes (as defined in the Act), the Tennessee Valley Authority, and any Alaska Native Corporation. The direct pay option is subject to an annual election and must be claimed by a partnership or S corporation rather than its partners or S corporation shareholders. Refunds under the direct pay provisions are treated the same as tax credits for purposes of basis reduction, depreciation rules, and recapture.

For qualifying facilities electing direct pay that do not meet the domestic content requirements, a reduction applies for projects beginning construction in 2024 (90%) and 2025 (85%). Thereafter, the direct pay option will not be available for projects that do not satisfy the domestic content requirement.

TRANSFERRABLE CREDITS

The IRA allows eligible taxpayers that do not elect the direct pay option to transfer certain credits to unrelated taxpayers including, among others, the ITC, PTC, clean hydrogen, and carbon capture credits. The transferred credit must be exchanged for cash. Credits may only be transferred once. Carryforwards or carrybacks are not transferable. Payments made to the transferor of the credit are not taxable to the transferor, nor is the payment by the transferee to the transferor deductible to the transferee.

The credit period for transferred credits is 23 years (including three years for carrybacks). The credit must be used in earliest possible year of transferee. A 20% penalty may apply for both direct payments and transfers where excessive payments have occurred.

Zero Emission Nuclear Power Production Credit

The Act includes a new PTC for the production of electricity from an existing nuclear facility that was placed in service before the date of enactment of the Act. To qualify, the electricity from the facility must be produced and sold to an unrelated person after December 31, 2023. The credit terminates on December 31, 2032. The base PTC amount is 3 cents per kWh, but is increased five times if wage and apprenticeship requirements are met (to 1.5 cents per kWh), in each case adjusted annually for inflation and reduced by a reduction amount to the extent electricity from the plant is sold at a price over $0.025/kWh.

Electric Vehicles and Hydrogen-Fueled Cars

The Act includes a $7,500 credit for taxpayers purchasing new electric vehicles and a $4,500 tax credit for used ones. The Act eliminates the previous “per-manufacturer” limits that applied to the new vehicle credit, but imposes new domestic content and assembly requirements, as well as caps on the retail price of new vehicles, and the income of the taxpayers purchasing the vehicle.

The Act also sets aside financing and credits to promote electric vehicle manufacturing. It calls for $2 billion in grants to help convert existing auto manufacturing factories into ones that make electric vehicles and $20 billion of loans for new clean vehicle manufacturing facilities. The Act extends the credits to hydrogen-fueled cars in addition to EVs.

Alternative Fuel Refueling Property Credit

The Act revives the expired credit for alternative fuel refueling property (i.e., electric vehicle chargers), allowing it for property placed in service before December 31, 2032. The base credit is 6% of the cost of property, and is increased to 30% if wage and apprenticeship requirements are met. The previous $30,000 cap is also increased to $100,000.

OFFSHORE WIND

The IRA puts in place a 10-year window in which a lease for offshore wind development cannot be issued unless an oil and gas lease sale has also been held in the year prior and is not less than 60 million acres. The Act also withdraws the Trump administration’s moratorium on offshore wind leasing in the southeastern U.S. and eastern Gulf of Mexico.

GREEN BANK

The Act includes $27 billion toward a clean energy technology accelerator to support deployment of emission-reduction technologies, especially in disadvantaged communities. The EPA Administrator would be permitted to disburse $20 billion to “eligible recipients,” which are defined as non-profit green banks that “provide capital, including by leveraging private capital, and other forms of financial assistance for the rapid deployment of low- and zero-emission products, technologies, and services.

Clean Fuel Production Credit

The Act creates a new tax credit for domestic clean fuel production starting in 2025 and expires for transportation fuels sold after December 31, 2027. The tax credit is calculated as the applicable amount multiplied by the emissions factor of the fuel. The base credit is $0.20 per gallon of transportation fuel produced at a qualified facility and sold, which increases to $1.00 if prevailing wage requirements are met. The base credit is $0.35/gallon for sustainable aviation fuel, $1.75 if labor and wage requirements are satisfied. The emissions factor of the fuel may reduce the credit amount. The credits are adjusted for inflation. The credit cannot be claimed if other clean fuel credits are claimed, including clean hydrogen production.

Article By Kris J. Eimicke and Merrill Kramer of Pierce Atwood LLP

For more energy and environmental legal news, click here to visit the National Law Review.

©2022 Pierce Atwood LLP. All rights reserved.

Key Takeaways from U.S. Supreme Court Decision in West Virginia v. EPA

On June 30, 2022, the U.S. Supreme Court issued its decision in West Virginia v. EPA, 597 U.S. __, 2022 WL 2347278 (June 30, 2022), a case involving the Obama Administration’s Clean Power Plan (CPP) and the Trump Administration’s Affordable Clean Energy (ACE) Rule. Applying the “major questions” doctrine, the Court held that EPA exceeded its statutory authority when promulgating the CPP. This decision has implications for the Biden Administration’s planned re-work and reissuance of the CPP and other options for reducing greenhouse gas (GHG) emissions from the electric power and other sectors. It also carries implications outside the environmental realm, providing litigants a powerful new administrative law precedent to challenge agency rules.

Key Takeaways and Issues to Watch

1. “Major questions” doctrine. The most significant takeaway of the opinion is the Court’s elaboration and application of the “major questions” doctrine, as a limit on federal agency regulatory authority. Chief Justice Roberts’ majority opinion held that in “certain extraordinary cases” where an agency asserts broad authority of “economic and political significance,” courts should look for a clear statement of congressional authorization before green-lighting the action. Based on the “major questions” doctrine, the Court rejected the CPP’s partial reliance on generation shifting (from coal-fired power plants to natural gas or renewable electricity generation) as a component of the “best system of emission reduction” (BSER) for reducing carbon dioxide from coal-fired power plants. The Court held that Clean Air Act Section 111(d), 42 U.S.C. § 7411(d), a rarely-used statutory provision, was not sufficient to support a rulemaking that “restructure[ed] the Nation’s overall mix of electricity generation….” Because the Court determined this result would carry consequences of economic and political significance, the Court found the rule triggered the “major questions” doctrine. The Court reiterated that although Section 111(d) authorizes EPA to establish emission guidelines for existing major sources of air pollution based on BSER, the Agency could not do so using such transformative measures.

This decision represents the Supreme Court’s first formal assertion of the “major questions” doctrine, applicable when an agency claims broad authority based on new interpretations of older statutes or statutes in which the grant of authority is not explicitly stated. Although this was not the first Supreme Court case employing this logic, this was the first case where the Court formally used the phrase “major questions” doctrine. Other cases the Court pointed to include a 2000 case rejecting the asserted authority of the Food and Drug Administration (FDA) to regulate tobacco products, like cigarettes, as drug-delivery “devices,” and more recent cases from this Supreme Court term concerning the authority of the Occupational Safety and Health Administration and the Centers for Disease Control and Prevention (CDC) to apply long-extant legal authorities in the context of COVID-19.

2. Chevron deference doctrine. The Court does not strike down Chevron as some parties had predicted or sought. That doctrine—requiring courts to defer to an agency’s reasonable construction of an ambiguous statute it is charged with administering—survives for now. Indeed, the majority opinion did not even cite Chevron deference.

3. Biden EPA. This decision immediately affects the scope of the Biden Administration’s approach to regulating power sector GHG emissions. The Administration has said that it wants to start these rules from a clean slate.

a. On-site measures. As noted in the decision, the Administration may be more likely to consider on-site measures as the BSER. Such options might include partial carbon capture and storage (CCS) or natural gas co-firing. The Obama EPA had declined to use those options for existing sources because it believed generation shifting was a less expensive way for industry to comply. But EPA had used partial carbon capture to set the limits for new sources, so it may review that issue now. Since the CPP’s issuance, the IRS Section 45Q tax credit for CCS and commercialization of CCS technologies that did not exist when the CPP was drafted may also affect the EPA’s approach now.

b. Generation shifting off the table. At least for setting the stringency of BSER, EPA will not be able to rely on generation-shifting measures. Advances in CCS technologies and the Section 45Q tax credit may also affect how EPA defines BSER for coal-fired plants in particular.

c. Seeking GHG reductions as “co-benefits” of other power sector rules. The Biden EPA may also consider other power plant emission rules under other CAA programs to achieve GHG reductions as “co-benefits.” Programs for regional haze, interstate air pollution, and hazardous air pollutants regulate other emissions, but often have the effect of reducing GHGs as well.

d. Other climate authorities will likely get a more intense look. The decision may also likely cause the Biden EPA to consider other, more clearly established GHG sources or authorities to seek additional GHG emissions reductions (e.g., mobile sources, HFCs).

4. Congressional action remains key. The Court’s decision underscores that certain rulemakings will need to rely on clear legislative authority to withstand legal challenges. Notably, the decision does not divest Congress from the ability to delegate “major questions” like this to federal agencies; it only requires that such delegations be clearly stated. Congress retains authority to act in any number of ways on climate change—including with economy-wide emissions programs (as it considered during the first Obama term), or by drafting clearer EPA authority—but with a narrowly-divided House and Senate, these actions seem unlikely.

5. Power sector practical effects. The practical outcome for the power sector is limited. That sector, in many respects, has already decarbonized at a rate faster than provided for by the CPP, largely for economic reasons.

6. States. This decision will likely encourage some states to use their authority to regulate GHG emissions, given the narrowed scope of EPA’s authority.

7. Future challenges. Expect litigants to rely heavily on the West Virginia decision in other rulemaking challenges going forward, whenever agencies act under existing authorities in a way that, in the Chief Justice’s words, “raises an eyebrow.” This may include not only EPA regulatory efforts to address modern environmental challenges, but actions of other federal agencies such as efforts by the Federal Communications Commission to regulate internet service providers to impose net neutrality, or efforts by the Securities and Exchange Commission to establish ESG disclosure requirements. Litigants will have a powerful tool to challenge those rules if they can persuasively phrase the question in “major question” terms.

Article By Eric L. Christensen, Brook J. Detterman, David M. Friedland, Jennifer J. Leech, and Zachary B. Pilchen of Beveridge & Diamond PC

For more environmental law legal news, click here to visit the National Law Review.

© 2022 Beveridge & Diamond PC

Court of Appeals Rules That Oil and Gas Company Has Ongoing Obligation to Restore Property Despite General Release of Damages in Surface Use Agreement

On April 11, 2022, the Fourth District Court of Appeals issued a significant decision in Zimmerview Dairy Farms, LLC v. Protégé Energy III LLC establishing that a general release of damages signed in connection with a pad site surface use agreement did not release the oil and gas company from its ongoing obligations to remediate and restore damage to a landowner’s property.

In the Zimmerview case, Plaintiff Zimmerview Dairy Farms (“ZDF”) signed a surface use agreement with Defendant Protégé Energy III LLC (“Protégé”) permitting Protégé to construct and operate a pad-site for Utica Shale wells on a portion of the ZDF farm. The agreement consisted of three documents: a recorded surface use agreement (favorable to Protégé); a confidential supplemental agreement (with terms favorable to ZDF); and a damage release under which ZDF released Protégé from the anticipated damages already paid for by Protégé. This three-document structure is typical, especially for pipelines easements, and one which many oil and gas companies insist on. Often, the damage release is explained by landmen as an unimportant formality and that the company is still going to fix the land as required under the unrecorded agreement. However, what a landman says, what an agreement says and what a company does can differ dramatically.

In Zimmerview, Protégé proceeded to construct and operate its pad-site without adequately remediating, restoring and reseeding the areas disturbed during construction, including the slopes of the pad-site. Over several years, Protégé’s failure to remediate resulted in significant topsoil damage, invasive weed infestations and ongoing erosion, which rendered large portions of the ZDF farm unusable. Protégé refused to pay or fix the ZDF farm, claiming that the damage release signed by ZDF released Protégé from any obligation to remediate or pay for damages caused to the ZDF farm. When ZDF filed suit and won at trial, Protégé appealed.

On appeal, Protégé once again argued that ZDF had released Protégé from all damages resulting from construction and operation of the pad-site including damages from not remediating the ZDF farm. Despite the broad language of the release, however, the Court of Appeals rejected Protégé’s argument on the basis that the damage release, signed when the surface use agreement was executed, could not have been intended to release Protégé from damages that resulted from the ongoing obligations and requirements Protégé had just agreed to under the surface use agreement. Accordingly, the Fourth District affirmed the trial court judgment (and $800,000 verdict for damages) against Protégé. Given the common use (and abuse) of similar damage releases by both operators and pipeline companies, this decision is a welcome addition to Ohio caselaw and should assist (and hopefully encourage) Ohio landowners to insist on producers and pipeline companies meeting their construction and remediation obligations.

©2022 Roetzel & Andress
For more articles about court cases, visit the NLR Litigation section.

EV Buses: Arriving Now and Here to Stay

In the words of Miss Frizzle, “Okay bus—do your stuff!”1 A favorable regulatory environment, direct subsidy, private investment, and customer demand are driving an acceleration in electric vehicle (EV) bus adoption and the lane of busiest traffic is filling with school buses. The United States has over 480,000 school buses, but currently, less than one percent are EVs. Industry watchers expect that EV buses will eventually become the leading mode for student transportation. School districts and municipalities are embracing EV buses because they are perceived as cleaner, requiring less maintenance, and predicted to operate more reliably than current fossil fuel consuming alternatives. EV bus technology has improved in recent years, with today’s models performing better in cold weather than their predecessors, with increased ranges on a single charge, and requiring very little special training for drivers.2 Moreover, EV buses can serve as components in micro-grid developments (more on that in a future post).

The Investment Incline

Even if the expected operational advantages of EV buses deliver, the upfront cost to purchase vehicles or to retrofit existing fleets remains an obstacle to expansion.  New EV buses price out significantly more than traditional diesel buses and also require accompanying new infrastructure, such as charging stations.  Retrofitting drive systems in existing buses comparatively reduces some of that cost, but also requires significant investment.3

To detour around these financial obstacles, federal, state, and local governments have made funding available to encourage the transition to EV buses.4 In addition to such policy-based subsidies, private investment from both financial and strategic quarters has increased.  Market participants who take advantage of such funding earlier than their competitors have a forward seat to position themselves as leaders.

You kids pipe down back there, I’ve got my eyes on a pile of cash up ahead!

Government funding incentives for electrification are available for new EV buses and for repowering existing vehicles.5 Notably, the Infrastructure Investment and Jobs Act committed $5 billion over five years to replace existing diesel buses with EV buses. Additionally, the Diesel Emissions Reduction Act provided $18.7 million in rebates for fiscal year 2021 through an ongoing program.

In 2021, New York City announced its commitment to transition school buses to electric by 2035.  Toward that goal, the New York Truck Voucher Incentive Program provides vouchers to eligible fleets towards electric conversions and covers up to 80% of those associated costs.6  California’s School Bus Replacement Program had already set aside over $94 million, available to districts, counties, and joint power authorities, to support replacing diesel buses with EVs, and the state’s proposed budget for 2022-23 includes a $1.5 billion grant program to support purchase of EV buses and charging stations.

While substantial growth in EV bus sales will continue in the years ahead, it will be important to keep an eye out for renewal, increase or sunset of these significant subsidies.

Market Players and Market Trends, OEMs, and Retrofitters

The U.S is a leader in EV school bus production:  two of the largest manufacturers, Blue Bird and Thomas Built (part of Daimler Truck North America), are located domestically, and Lion Electric (based in Canada) expects to begin delivering vehicles from a large facility in northern Illinois during the second half of 2022.  GM has teamed up with Lighting eMotors on a medium duty truck platform project that includes models prominent in many fleets, and Ford’s Super Duty lines of vehicles (which provide the platform for numerous vans and shuttle vehicles) pop up in its promotion of a broader electric future. Navistar’s IC Bus now features an electric version of its flagship CE series.

Additionally, companies are looking to a turn-key approach to deliver complete energy ecosystems, encompassing vehicles, charging infrastructure, financing, operations, maintenance, and energy optimization. In 2021, Highland Electric Transportation raised $253 million from Vision Ridge Partners, Fontinalis Partners (co-founded by Bill Ford) and existing investors to help accelerate its growth, premised on a turn-key fleet approach.7

Retrofitting is also on the move.  SEA Electric (SEA), a provider of electric commercial vehicles, recently partnered with Midwest Transit Equipment (MTE) to convert 10,000 existing school buses to EVs over the next five years.8 MTE will provide the frame for the school uses and SEA will provide its SEA-drive propulsion system to convert the buses to EV.9 In a major local project, Logan Bus Company announced its collaboration with AMPLY Power and Unique Electric Solutions (UES) to deploy New York City’s first Type-C (conventional) school bus.10

Industry followers should expect further collaborations, because simplifying the route to adopting an EV fleet makes it more likely EV products will reach customers.

Opportunities Going Forward

Over the long haul, EV buses should do well. Scaling up investments and competition on the production side should facilitate making fleet modernization more affordable for school districts while supporting profit margins for manufacturers. EVs aren’t leaving town, so manufacturers, fleet operators, school districts and municipalities will either get on board or risk being left at the curb.

Article By Michael J. Small and Samantha Ruppenthal at Foley & Lardner LLP

For more utilities and transportation legal news, click here to visit the National Law Review.

 

 

1https://shop.scholastic.com/parent-ecommerce/series-and-characters/magic-school-bus.html

2https://www.busboss.com/blog/having-an-electric-school-bus-fleet-is-easier-than-many-people-think

3https://thehill.com/opinion/energy-environment/570326-electric-school-bus-investments-could-drive-us-vehicle

4https://info.burnsmcd.com/white-paper/electrifying-the-nations-mass-transit-bus-fleets

5https://stnonline.com/partner-updates/electric-repower-the-cheaper-faster-and-easier-path-to-electric-buses/

6https://www1.nyc.gov/office-of-the-mayor/news/296-21/recovery-all-us-mayor-de-blasio-commits-100-electric-school-bus-fleet-2035

7https://www.bloomberg.com/press-releases/2021-02-16/highland-electric-transportation-raises-253-million-from-vision-ridge-partners-fontinalis-partners-and-existing-investors

8https://www.electrive.com/2021/12/07/sea-electric-to-convert-10k-us-school-buses/#:~:text=SEA%20Electric%20and%20Midwest%20Transit,become%20purely%20electric%20school%20buses.

9 Id.

10https://stnonline.com/news/new-york-city-deploys-first-type-c-electric-school-bus/

© 2022 Foley & Lardner LLP

Crossing the Wires of Energy and Cryptocurrency Policy: U.S. Congress Investigates the Environmental Impact of Crypto Mining

The rapid adoption of cryptocurrency and other popular blockchain applications has captured our global economy’s attention. Even as the value of cryptocurrencies slid from their all-time highs, the promise of these digital assets and the infrastructure being developed to support them has been transformative.

As with most emerging technologies, policymakers are still exploring the best approaches to regulating these new digital assets and business models. Questions about consumer protection, security, and the applicability of existing laws are to be expected; however, the environmental impact of these energy-intensive business practices has prompted considerable study and regulatory activity across the globe, including attention in the United States.

To understand the increasing energy demands associated with major cryptocurrencies – predominantly, Bitcoin and Ethereum – it is important to understand how many cryptocurrencies are generated in the first instance. Many countries, including China, have banned cryptocurrency mining, and, with the United States becoming the largest source of cryptocurrency mining activity, Congress began active investigations and hearings into the energy demands and environmental impacts in January 2022.

Proof of What? Why certain cryptocurrencies create high energy demands. 

Not all cryptocurrencies – or blockchain platforms, for that matter – are created equal in their energy demands. The goal of most major cryptocurrency platforms is to create a decentralized, distributed ledger, meaning that there is no one authority to verify the authenticity of transactions and ensure that assets are not spent twice, for example. There needs to be a trustworthy mechanism – a consensus system – to verify new transactions, add those transactions to the blockchain, and to confirm the creation of new tokens. Bitcoin alone has well over 200,000 transactions per day,[1] so it should not come as a surprise that these platforms take an enormous amount of processing power to maintain.

There are currently two primary ways that network participants lend their processing power, which are framing part of the modern energy policy debates around cryptocurrency. The first form is “proof of work,” which is the original method that Bitcoin and Ethereum 1.0 employ. When a group of transactions (a block) needs to be verified, all of the “mining” computers race to solve a complex math puzzle, and whoever wins gets to add the block to the chain and is rewarded in coins. The competitive nature of proof of work consensus systems has led to substantial increases in computing power provided by institutional cryptocurrency mining operations and, with that, higher energy demands.

The second form is “proof of stake,” which newer platforms like Cardano and ETH2 use, promises to require considerably less energy to operate. With this method, validators “stake” their currency for a chance at verifying new transactions and updating the blockchain. This method rewards long-term investment in a particular blockchain, rather than raw computing power. A validator is picked based on how much currency they have staked and how long it has been staked for. Once the block is verified, other validators must review and accept the data before it’s added to the blockchain. Then, everyone who participated in validating the block is rewarded with coins.

While proof of stake consensus systems are becoming more common, the dominant – and most valuable – cryptocurrencies are still generated through energy-intensive proof of work systems.

Turning out the lights on Crypto: China bans domestic mining and other countries follow.

China has been incredibly influential in the modern cryptocurrency debate around energy use. For several years, China was the cryptocurrency mining capital of the world, providing an average of two-thirds of the world’s processing power dedicated to Bitcoin mining through early 2021.[2] In June 2021, however, China banned all domestic cryptocurrency mining operations, citing the environmental impacts of Bitcoin mining energy demands among its concerns.[3]

As Bitcoin miners fled China, many relocated to neighboring countries, such as Kazakhstan, and the United States became the largest source of mining activity – an estimated 35.1% of global mining power.[4] The surge in Bitcoin mining activity in Kazakhstan has not been without its controversy. Many Kazakhstan-based crypto mining operations are powered by coal plants, and there has been considerable unrest sparked by rising fuel costs.[5]

With some countries experiencing negative impacts from cryptocurrency mining operations, several countries have followed China’s lead in banning cryptocurrencies. According to a 2021 report prepared by the Law Library of Congress, at least eight other countries – Egypt, Iraq, Qatar, Oman, Morocco, Algeria, Tunisia, and Bangladesh – have banned cryptocurrencies.[6] Many other countries have impliedly banned cryptocurrency or cryptocurrency exchanges, as well.[7]

U.S. Congress shines its spotlight on the energy demands of cryptocurrency mining.

Now home to over a third of the global computing power dedicated to mining bitcoin, the United States has turned its attention to domestic miners and their impacts on the environment and local economies.

In June 2021, U.S. policymakers were still predominantly focused on the consumer protection and security concerns raised by digital currencies; however, Senator Elizabeth Warren alluded to her growing concerns about the environmental costs of, particularly, proof of work mining.[8] On December 2, 2021, Senator Warren sent a letter requesting information on the environmental footprint of New York-based Bitcoin miner Greenridge Generation.[9] The letter observed that, “[g]iven the extraordinarily high energy usage and carbon emissions associated with Bitcoin mining, mining operations at Greenridge and other plants raise concerns about their impacts on the global environment, on local ecosystems, and on consumer electricity costs.”[10] Senator Warren’s concerns sparked several rounds of congressional oversight and inquiries into the environmental impacts of, particularly, proof of work cryptocurrencies, over the past month.

Committee Hearing on “Cleaning up Cryptocurrency” begins oversight and investigation into the energy impacts of blockchains.

On January 20, 2022, the U.S. House of Representatives Committee on Energy and Commerce’s Subcommittee on Oversight and Investigations held a hearing, where the externalities of cryptocurrency mining were the focus of the agenda. An early indicator of the Subcommittee’s views on the issue, the title for the hearing was “Cleaning up Cryptocurrency: The Energy Impacts of Blockchains.”[11]

The hearing focused heavily on the amount of energy used to power proof of work cryptocurrency mining. Bitcoin Mining has been widely criticized for the massive amounts of power it consumes – globally, more than 204 terawatt-hours as of January 2022. Although some operations are attempting to utilize renewable energy, the machines executing these algorithms consume enormous amounts of energy primarily sourced from fossil fuels.

The five industry experts testifying before the House Energy and Commerce Oversight Subcommittee had competing views on how regulators should address the energy consumption of cryptocurrencies—with some experts opining that the computational demands were a “feature, not a bug.”[12] Two of the experts – Brian Brooks, CEO of Bitfury Group, and Professor Ari Juels, Faculty member at Cornell Tech – debated the technical merits between proof of work and proof of stake systems, described earlier in this article.[13] Similarly, Gregory Zerzan, an attorney with Jordan Ramis, P.C. who previously held senior positions in the United States Government, encouraged the Subcommittee not to lose sight of the fact that cryptocurrencies are but “one aspect of a larger innovation, blockchain.”[14] Although the viewpoints of the experts varied considerably, there was a clear consensus among the experts: energy-efficient alternatives should guide the path forward.

John Belizaire, the founder and CEO of Soluna Computing, said that cryptocurrency mining could further accelerate the transition to renewable energy sources from an energy perspective.[15] Renewables currently suffer from one significant deficiency – intermittency. An example of this challenge is the so-called “duck curve,” which illustrates major differences between the demands for electricity as compared to the amount of renewable energy sources available throughout the day. For example, when the sun is shining, there is significantly more power than consumers need for a few hours per day; however, solar energy does not provide nearly enough energy when demand spikes in the late afternoon and evening.[16] While there has been progress in the development of lithium battery storage – a critical piece in solving the issues mentioned above– for the time being, deploying these batteries at scale is still too expensive.

In addressing gaps in battery storage, Belizaire testified that “Computing is a better battery.”[17] Computing, he states, “is an immediately deployable solution that can allow renewables to scale to their full potential today.”[18] Belizaire highlighted that, unlike other industrial consumers, cryptocurrency miners can turn their systems off when necessary, giving miners the ability to absorb excess energy from a given area’s electrical grid rather than straining it. This ability to start and stop or pause computing processes can increase grid resilience by absorbing excess energy from renewable resources that provide more power than the grid can handle. Brooks shared similar hopes for how Bitcoin mining could help stabilize electric grids, support the viability of renewable energy projects, and drive innovation in computing and cooling technology.[19]

Steve Wright, the former general manager of the Chelan County Public Utility District in Washington, testified that “the portability of cryptocurrency operations could be a benefit in terms of locating operations based on underutilized transmission and distribution capacity availability.”[20] Still, with ambitious goals to expand transmission and increase and integrate large amounts of carbon-free emitting generation, Wright testified that “substantial collaboration and coordination will be necessary to avoid cryptocurrency mining exacerbating an already very difficult problem.”[21]

Congressional Democrats continue the investigation into domestic mining operations and the Cryptomining Industry response.

The January 20, 2022 Hearing made clear that policymakers are doing their due diligence into the impact that the United States could experience as the number of domestic cryptocurrency mining operations increase. Commentary from the Hearing forecasted that scrutinizing the sources and costs of energy used in cryptocurrency mining would be a priority for Democrat members of Congress.

To that end, on January 27, 2022, eight Democrat members of Congress led by Senator Elizabeth Warren “sent letters to six cryptomining companies raising concerns over their extraordinarily high energy uses.”[22] Citing the same concerns raised in her December 2021 letter to Greenridge, Senator Warren and her colleagues observed that “Bitcoin mining’s power consumption has more than tripled from 2019 to 2021, rivaling the energy consumption of Washington state, and of entire countries like Denmark, Chile, and Argentina.”[23] To assist Congress in its investigation, Riot Blockchain, Marathon Digital Holdings, Stronghold Digital Mining, Bitdeer, Bitfury Group, and Bit Digital were all asked for information related to their mining operations, energy consumption, possible impacts on the climate and local environments, and the impact of electricity costs for American consumers.[24] Senator Warren and her colleagues requested written responses by no later than February 10, 2022, so this increased oversight will likely continue.

Even with increased oversight, current trends in crypto mining and renewables could soon make such inquiries a moot point. Amid the heated debate over the environmental impact of cryptocurrencies, miners are increasingly committed to changing the negative reputation that it has built over the years – especially as these operations move to the United States. In November of last year, Houston-based tech company Lancium announced that it raised $150 million to build bitcoin mines across Texas that will run on renewable energy.[25] In 2022, the company plans to launch over 2,000 megawatts of capacity across its multiple sites.[26] Bitcoin mining company Argo Blockchain, a company listed on the London Stock Exchange, secured a $25 million loan to fund its “green” mining operation.[27] The 320-acre site will only use renewable energy, the majority being hydroelectric.[28] This deal is set to transform Argo’s mining capacity and is expected to be completed in the first half of 2022.[29]

Capital Markets also appear to have a growing appetite for the development of green crypto mining. In April of last year, Gryphon Digital Mining raised $14 Million Series A to launch a zero-carbon footprint Bitcoin mining operation powered exclusively by renewables.[30] In a raise that closed in just over two weeks, institutional investors – who were significantly oversubscribed – accounted for over thirty percent of the round.[31]

As congressional, social, and economic pressures grow, it is evident that there is going to be a big focus on the sustainability of Bitcoin mining. As such, we may very well see announcements, like the deals mentioned above, well into 2022 and beyond.

FOOTNOTES

[1] Bitcoin Transactions Per Day, YCharts, https://ycharts.com/indicators/bitcoin_transactions_per_day (last visited Jan. 29, 2022).

[2] Bitcoin Mining Map, Cambridge Centre for Alternative Finance, https://ccaf.io/cbeci/mining_map (last visited Jan. 29, 2022) [“Bitcoin Mining Map”].

[3] Samuel Shen & Andrew Galbraith, China’s ban forces some bitcoin miners to flee overseas, others sell out, Reuters, June 25, 2021, https://www.reuters.com/technology/chinas-ban-forces-some-bitcoin-miners-flee-overseas-others-sell-out-2021-06-25/ (last visited Jan. 29, 2022).

[4] See Bitcoin Mining Map.

[5] Tom Wilson, Bitcoin network power slumps as Kazakhstan crackdown hits crypto miners, Reuters, Jan. 7, 2022, https://www.reuters.com/markets/europe/bitcoin-network-power-slumps-kazakhstan-crackdown-hits-crypto-miners-2022-01-06/ (last visited Jan. 29, 2022).

[6] Regulation of Cryptocurrency Around the World: November 2021 Update, Global Legal Research Directorate, The Law Library of Congress, available at https://tile.loc.gov/storage-services/service/ll/llglrd/2021687419/2021687419.pdf (last visited Jan. 29, 2022).

[7] Id.

[8] Press Release, United States Senate Committee on Banking, Housing, and Urban Affairs, At Hearing, Warren Delivers Remarks on Digital Currencies (June 9, 2021), https://www.banking.senate.gov/newsroom/majority/at-hearing-warren-delivers-remarks-on-digital-currency (last visited Jan. 29, 2022).

[9] Elizabeth Warren, Letter to Greenridge Generation on Crypto, Dec. 2, 2021, available at https://www.warren.senate.gov/imo/media/doc/2021.12.2.%20Letter%20to%20Greenidge%20Generation%20on%20Crypto.pdf (last visited Jan. 29, 2022).

[10] Id. at p.2.

[11] Hearing Notice, United States House Committee on Energy & Commerce, Hearing on “Cleaning Up Cryptocurrency: The Energy Impacts of Blockchains” (Jan. 20, 2022), https://energycommerce.house.gov/committee-activity/hearings/hearing-on-cleaning-up-cryptocurrency-the-energy-impacts-of-blockchains (last visited Jan. 29, 2022) [the “January 20 Hearing”].

[12] January 20 Hearing Testimony. See also Statement of Brian P. Brooks before House Committee (Jan. 20, 2022), available at https://energycommerce.house.gov/sites/democrats.energycommerce.house.gov/files/documents/Witness%20Testimony_Brooks_OI_2022.01.20_0.pdf  (last visited Jan. 29, 2022) [the “Brooks Statement”].

[13] See, e.g., Brooks Statement; Statement of Prof. Ari Juels before House Committee (Jan. 20, 2022), available at https://energycommerce.house.gov/sites/democrats.energycommerce.house.gov/files/documents/Witness%20Testimony_Juels_OI_2022.01.20.pdf (last visited Jan. 29, 2022) [the “Juels Statement”].

[14] Statement of Gregory Zerzan before House Committee (Jan. 20, 2022), available at https://energycommerce.house.gov/sites/democrats.energycommerce.house.gov/files/documents/Witness%20Testimony_Zerzan_OI_2022.01.20.pdf (last visited Jan. 29, 2022).

[15] See, e.g., Statement of John Belizaire before House Committee (Jan. 20, 2022), available at https://energycommerce.house.gov/sites/democrats.energycommerce.house.gov/files/documents/Witness%20Testimony_Belizaire_OI_2022.01.20_0.pdf (last visited Jan. 29, 2022) [the “Belizaire Statement”].

[16] Office of Energy Efficiency & Renewable Energy, Confronting the Duck Curve: How to Address Over-Generation of Solar Energy (October 12, 2017)

https://www.energy.gov/eere/articles/confronting-duck-curve-how-address-over-generation-solar-energy (last visited Jan. 29, 2022).

[17] See, e.g., Belizaire Statement, p.4.

[18] Id.

[19] See generally Brooks Statement, pp.8-10.

[20] See, e.g., Statement of Steve Wright before House Committee, p.5 (January 20, 2022) available at https://energycommerce.house.gov/sites/democrats.energycommerce.house.gov/files/documents/Witness%20Testimony_Wright_OI_2022.01.20.pdf (last visited Jan. 29, 2022) [the “Wright Statement”].

[21] Id. p.9.

[22] Press Release, Office of Senator Elizabeth Warren, Warren, Colleagues Press Six Cryptomining Companies on Extraordinarily High Energy Use and Climate Impacts (Jan. 27, 2022), available at https://www.warren.senate.gov/newsroom/press-releases/warren-colleagues-press-six-cryptomining-companies-on-extraordinarily-high-energy-use-and-climate-impacts (last visited Jan. 29, 2022).

[23] Id.

[24] Id.

[25] MacKenzie Sigalos, This Houston Tech Company wants to build renewable energy-run bitcoin mines across Texas CNBC (November 23, 2021), https://www.cnbc.com/2021/11/23/lancium-raises-150-million-for-renewable-run-bitcoin-mines-in-texas.html (last visited Jan 31, 2022).

[26] Id.

[27] Namcios Bitcoin Magazine, Argo blockchain buys Hydro data centers to realize Green Bitcoin Mining Vision, (May 13, 2021), https://www.nasdaq.com/articles/argo-blockchain-buys-hydro-data-centers-to-realize-green-bitcoin-mining-vision-2021-05-13 (last visited Jan 31, 2022).

[28] Id.

[29] Id.

[30] GlobeNewswire News Room, Gryphon Digital Mining raises $14 million to launch bitcoin mining operation with zero carbon footprint, (April 13, 2021), https://www.globenewswire.com/newsrelease/2021/04/13/2209346/0/en/Gryphon-Digital-Mining-Raises-14-Million-to-Launch-Bitcoin-Mining-Operation-with-Zero-Carbon-Footprint.html (last visited Jan 31, 2022).

[31] Id.

Copyright ©2022 Nelson Mullins Riley & Scarborough LLP
For more articles about cryptocurrency, visit the NLR Financial Securities & Banking section.

Electrification of the Fleet is on the Horizon, Preparing Now is Key

While we often hear how EVs will revolutionize the lives of the average consumer, commercial fleet owners are starting to take note of the impact these new powertrain systems will have on their own business and operations. As OEMs find creative ways to increase aerodynamics, extend battery range, and increase charging speeds, the zero emission and lower long-term cost of EVs compared to ICE (internal combustion engine) vehicles makes a compelling argument for adoption, at least on paper. What really matters is how those factors play out as the rubber hits the road, which OEMs are starting to see play out in real time. Over the past few years, there has been an explosion of commercial fleet platforms from existing and new entrants in the commercial vehicle space. From light to heavy trucking to fleet platform automobiles, EV technology is looking to capture every corner of the commercial fleet sector. Coupled with a slow reduction in the number of ICE vehicles produced in future years, the market may start pushing fleet operations towards EVs, whether they like it or not.

According to the Department of Transportation, over eight million vehicles made up commercial fleets in the US in 2020, which includes a mix of trucks and automobiles used in commercial and government operations. Even more make up commercial vehicles on the road that are not considered part of a fleet. As consumer demand drives most traditional OEMs toward EV dominated fleets, commercial fleet owners and operators need to start to prepare now for the same shift in their vehicle suppliers, or risk playing catchup once the market does turn from ICE to EV. This isn’t to say that failure to be an early adopter will be the death-knell to commercial fleet businesses; it likely won’t be. What businesses with commercial fleets should consider is their own business needs and their timeline for their own fleet replacement as EV technology and infrastructure support continues to evolve. Establishing a process and plan for upgrading existing fleets, training personnel, upgrading infrastructure, and understanding available programs for conversion will be key.

The switch from an ICE to EV fleet isn’t as simple as flipping a switch or plugging in a car – EVs bring a new powertrain and new sources of information. EVs in their current state are expensive, new vehicle supply is constantly in question, current operators are unaware of the nuances involved with operating an EV, and the infrastructure necessary to support a commercial fleet of EVs isn’t universally robust. For the average fleet operator, there also is a need to focus on route optimization, installing and maintaining new hardware capable to supporting charging on-site, revamping their maintenance and care procedures, and working with their local energy providers to understand how power demands in their local market may impact their own energy costs and needs. Additionally, although data analytics has improved existing fleet operations over the past few years, expect to see more nuanced data availability to the benefit of fleet operators.  As commercial and consumer EVs come out with ever more connectivity to the web and each other, coupled with the ability for “smart cities” to increase data available to drivers and vehicles, expect future fleet operators to get even more granular and predictive understanding of traffic patterns to optimize commercial routes. Managing these dynamics and capitalizing on new sources of information will better enable operators to adapt to the changing landscape. The ability to adapt to this new frontier will be a key trait for successful fleet operations in the Auto-2.0 operated environment.

Article By Christopher R. Boll of Foley & Lardner LLP

For more infrastructure and transportation legal news, click here to visit the National Law Review.

© 2022 Foley & Lardner LLP

DOER Finalizes SMART Program Emergency Regulations

The Department of Energy Resources (DOER) has finished the required Solar Massachusetts Renewable Target (SMART) Program 400MW review and emergency rulemaking and published its final regulations. Several revisions and adjustments have been made to the final regulations, including an extension to the COVID-19 extension for new applications received through December 31, 2020.

Revisions have been made to previously published land-use exceptions. Projects that meet the below criteria will now be assessed under the former land-use regulations:

  • Have applied for the Interconnection Service Agreement (ISA) 135 business days prior to April 15, 2020, or have obtained a fully executed ISA by October 15, 2020; and
  • Have obtained a sufficient interest in real estate or other contractual rights to construct the Solar Tariff Generation Unit at the location specified in the ISA as of April 15, 2020.

Additionally, the DOER distinguished eligible land use between projects qualifying for capacity as part of the original 1600MW versus projects qualifying under the new 1600MW. Projects qualifying under the original 1600MW will be eligible for the SMART Program even if located on land designated as Critical Natural Landscape, while projects qualifying under the new 1600MW will be ineligible if the project is sited in a Priority Habitat, Core Habitat, or Critical Natural Landscape.

The final regulations also allow for single-axis trackers to be eligible for the Tracker Adder, and behind-the-meter systems to receive Alternative On-Bill Credits.

The DOER also made modifications to the Statement of Qualification Reservation Period Guideline. In addition to continuing the COVID-19 extension for new applications, the DOER has done the following:

  • Eliminated the requirement that projects obtaining an indefinite extension, pending the authorization to interconnect, must submit a claim within 10 business days of receiving the authorization to interconnect;
  • Granted eligible Public Entity Off-taker Adder Solar Tariff Generation Units an initial Reservation Period of 18 months;
  • Clarified that projects qualified as Community Shared Solar that do not submit a claim with the CSS Adder will have their base compensation rate decreased to the value in the lowest available Capacity Block, but will not be at risk of losing their Statement of Qualification outright: and
  • Established a process by which DOER will queue project applications if there is a rush of applications submitted following the issuance of ISAs by a Distribution Company upon the completion of an ASO study.

Several other Guidelines related to the SMART Program are still being revised, and the DOER is expected to release these updates in the coming weeks. Publication of the regulations is just the beginning phase for resuming the SMART Program. Changes to the regulations that affect the tariff will now need to be implemented into each Electric Distribution Companies’ tariffs and undergo administrative review of the Department of Public Utilities.

© 2020 SHERIN AND LODGEN LLP

For more on solar renewable energy, see the National Law Review Environmental, Energy & Resources law section.

Battle of the Benchmarks: Brent Crude Oil and West Texas Intermediate

Brent Crude Oil (Brent) and West Texas Intermediate (WTI) are the two leading global benchmark references for crude oil prices. Historically, the two have often tracked very closely to each other, without significant price variations. The exceptions were the period between 2011 and 2015, when prices for the two diverged dramatically, and, to a lesser extent, the period since mid-2017.

Figure 1: Spread between WTI and Brent Futures Prices
1/1/2000-2/28/2019

Source: Bloomberg

Note: The spread is calculated as the price of the WTI futures contract closest to expiry minus the Brent futures contract closest to expiry.
These prices are represented on Bloomberg as CL1 and CO1 respectively. CL1 trades on NYMEX and CO1 trades on ICE.

One reason for the first price divergence was the growth of U.S. crude production of WTI. Without the necessary infrastructure or regulatory certainty to facilitate crude exports from the U.S. and provide an outlet for this additional supply, WTI prices decreased relative to Brent, and trading volume in Brent futures contracts overtook WTI futures. Between 2015 and mid-2017, however, both infrastructure and regulatory changes in the U.S. led to price parity becoming the norm again.

In mid-2017, prices began to diverge a second time as increases in crude prices led to a renewal of production growth and also contributed to a destocking of U.S. crude inventory. These and other market factors have caused the battle for benchmark supremacy to heat up again. In this latest round, WTI futures volumes are overtaking Brent futures.

This article examines the evolution and relationship between these two benchmarks and what factors have impacted their prominence as a benchmark.

About the Benchmarks

While crude oil is not a homogeneous commodity, over time market conventions have gravitated towards the use of standardized benchmark reference rates. Each unique grade of crude is typically priced at a discount or premium relative to benchmark rates to reflect its quality, characteristics, and location. Benchmark grades tend to have certain characteristics, including large production volumes, stable market environments, and consistent quality characteristics.

Both Brent and WTI are considered higher-quality crudes relative to crude oil produced in the Middle East and Russia, and require less refining to produce useable petroleum products.[i] Both are often referred to as “light and sweet” because of their high quality.[ii]

Their futures trading volumes have grown substantially over time, averaging more than eight times the volume in 2018 than in 2000. This increase is often explained by price volatility, the use of commodities as inflation protection, and an expansion of tradable products to better meet the needs of market participants.[iii]

Figure 2: Monthly Volume Comparison of ICE Brent and CME WTI Futures
1/1/2010-2/28/2019

Figure 2

Source: Bloomberg

Note: The aggregate future volume is the sum of the volumes of all maturities of ICE Brent and CME WTI futures. All futures volumes are aggregated on a monthly basis.

These benchmarks, however, are distinct in many ways. Brent, a European crude benchmark, is based on production from multiple oilfields in the North Sea. WTI is a U.S. crude benchmark that reflects the land-based crude oil stored in Cushing, Oklahoma.

In addition, while both Brent and WTI have developed futures markets with high volumes and many participants, Brent trades mainly on the Intercontinental Exchange (ICE) and WTI trades mainly on the CME Group (CME).

Surge of U.S. Crude Gives Brent the Edge

Between 2010 and 2018, extraction from shale reserves almost doubled the overall production of crude oil in the U.S. This growth was driven by new technological advancements that enabled horizontal drilling and fracking, coupled with historically high crude prices that led to massive infrastructure investments. Most of the new production came from PADD 3, comprising states in the Gulf Coast (see Appendices A and B). Expanded production resulted in increased supply and inventory of domestic oil in Cushing, Oklahoma, the main storage and pipeline hub for U.S. crude.

Figure 3: Total Quarterly Production of Crude Oil in North Sea and United States[iv]
Q1 2010-Q4 2018

Figure 3 Total

Source: Dow Jones; Reuters News; U.S. Energy Information Administration

Note: The Seaway pipeline began pumping oil from Cushing, Oklahoma, to Houston, Texas, from May 19, 2012, to reverse the direction of the oil flow. The reversed service line had an initial capacity of 150,000 bpd and increased to 400,000 bpd in January 2013 and 850,000 bpd in July 2014.

Until 2010, WTI generally traded at a small premium over Brent, due in part to its lighter and sweeter characteristics. Given the increasing supply of U.S. crude, however, WTI prices declined relative to Brent, reaching a discount of more than $27 in October 2011.

WTI Catches Up

Two significant events helped to reverse the price disparity between WTI and Brent. The first was an investment in infrastructure to bring the oil to market.

Cushing, Oklahoma, is landlocked and inaccessible by tanker or barge, and pipelines are key to moving crude. When U.S. crude oil production increased rapidly, the existing pipeline was positioned to pipe crude into, but not out of, Cushing. In May 2012, Seaway Crude Pipeline Company LLC reversed the flow of the Seaway pipeline in order to pipe crude from Cushing to the Gulf Coast. When it reached full capacity in January 2013, the Seaway pipeline began moving about 400,000 bpd of crude oil to Texas. A twin (loop) of the pipeline, designed to run parallel to the existing line, was built and doubled the transportation capacity of crude oil to 850,000 bpd starting in July 2014.[v] An additional 100,000 bpd expansion is scheduled to come online in the first half of 2019.[vi]

The second event was a change in trade policy by the federal government. Traditionally, the U.S. government has tightly controlled oil exports. In fact, for 40 years, it had enforced a ban on exporting crude oil, allowing only minor exceptions such as oil shipped through the Trans-Alaska Pipeline, heavy oil from certain fields in California, and some small trades with Mexico.[vii]

At the end of 2015, the government lifted the ban on exporting crude oil from the continental U.S. Crude oil no longer had to be refined or lightly refined before exporting.[viii] Since the repeal of the ban, crude oil exports have risen, prompted by the increase in oil prices and by OPEC’s drive to cut production.[ix]

Figure 4: Weekly Levels of U.S. Crude Oil
1/1/2010-2/28/2019

Source: U.S. Energy Information Administration; Bloomberg

Note:

1. In the past, the U.S. Commerce Department had given export licenses for particular types of oil. Crude from Alaska’s Cook Inlet, oil passing through the Trans-Alaska Pipeline, oil shipped north for Canadian consumption, heavy oil from particular fields in California, some small trades with Mexico, and some exceptions for re-exporting foreign oil made up those exports.

2. The WTI futures is the price of the futures contract on WTI traded on CME closest to expiry (front month) on any given day. The Bloomberg ticker for this is CL1.

Another factor that expanded trading options for physical oil traders was the widening of the Panama Canal in mid-2016. The locks in the canal were widened to 180 feet from 109 feet and became accessible to new, larger ships called New Panamax that can carry more than twice as much cargo as previous ships crossing the canal (see Appendix C).[x] The waterway shrinks distances between refineries situated along the Gulf of Mexico and Asia to 9,000 miles from 16,000 miles, allowing U.S. producers to better compete in one of the world’s biggest oil-consuming markets.

On a global scale, the U.S. produces about 10 percent of the world’s crude oil, and exports less than 15 percent of its total production, making up less than 2 percent of global volumes.[xi] As of late January 2019, U.S. output had surpassed daily production in Russia and Saudi Arabia, making the U.S. the world’s leading oil producer. Although the U.S. export volumes may be small, they are important because they represent additional market options for the increasing production in the U.S., and U.S. production is able to quickly respond to global market factors and supply the marginal crude oil necessary to fill temporary fluctuations in demand.[xii] 

With WTI’s improved access to the Gulf Coast and with the export ban lifted, U.S. crude producers and exporters have more options regarding where and to whom to sell the crude.

New Supply Resumes Downward Price Pressure

Since mid-2017, the U.S. crude oil industry has witnessed a renewal in production growth. Production in Q4 2018 was 30 percent higher than Q2 2017 (see Figure 3). This growth was largely driven by an increase in crude oil prices from a range of $25-$55 a barrel between 2016 and H1 2017, to $60-$75 a barrel between the beginning of 2018 and the end of Q3 2018.

Additionally, as prices rose, crude oil kept in storage during the period of lower prices was destocked. In other words, it was no longer profitable to store oil because current prices exceeded the cost of storage and anticipated future prices. For a time, the futures forward curve shifted from contango to backwardation.[xiii]

Figure 5: Storage Capacity Utilization of U.S. Crude Oil
3/2011-9/2018

Storage Capacity

Source: U.S. Energy Information Administration

Note: Alternate Utilization Rate measures crude oil stores in tanks as well as crude oil in pipelines and in transit by rail in proportion to the sum of the tanks’ working storage capacity and stocks in transit.

These factors contributed to WTI prices decreasing relative to Brent prices and, as of early 2019, WTI was trading at close to a $10 discount to Brent. Interestingly, unlike the prior divergence in prices, growth in the trading of the WTI futures contract has outpaced that of Brent futures contracts (see Figure 2).

Figure 6: WTI and Brent Futures Prices
1/1/2003-2/28/2019

Source: Bloomberg

Note:

1. The WTI futures contract is the price of the futures contract on WTI traded on NYMEX closest to expiry (front month) on any given day.
The Brent futures contract is the price of the (front month) futures contract on Brent traded on ICE closest to expiry on any given day.
The Bloomberg tickers for these are CL1 and CO1 respectively.

2. The Seaway pipeline began pumping oil from Cushing, Oklahoma, to Houston, Texas, on May 19, 2012, to reverse the direction of the oil flow. The reversed service line had an initial capacity of 150,000 bpd and increased to 400,000 bpd in January 2013 and 850,000 bpd in July 2014.

Brent Crude Loses Steam

At the same time that U.S. crude production was booming, and trade policy was becoming less restrictive, production at the original oil fields that comprise Brent was steadily declining, including at the eponymous Brent oilfield (see Figure 3).

As production decreased, the composition of the benchmark changed with the gradual addition of new oil fields. These oilfields include Forties and Oseberg (added in 2002) and Ekofisk (added in 2007). Brent’s production base is thus referred to by the acronym of the four crude oil streams: BFOE. A fifth stream, Troll, was added in 2018, referred to as BFOE-T.[xiv]

The addition of Troll was an attempt to maintain a robust production base to support the Brent benchmark. In late 2018, S&P Global Platts (Platts) initiated an industry consultation on whether to make two additional changes to the benchmark. The first is to add Rotterdam cost-and-freight price (CIF) for the North Sea grades, which would likely double the volume of crude underlining the benchmark. The second is to include Russian, Central Asian, West African, or U.S. shale field crude in the Brent benchmark.[xv]

As each new field is added, the quality of oil and the ownership structure of what is considered Brent crude oil changes slightly (see Appendix D). The original Brent field oil has an API gravity of 37.5 degrees and a sulfur content of 0.4 percent, making it light and sweet.[xvi] However, the addition of the Forties field, which cannot be considered sweet as it exhibits sulfur content as high as 0.82 percent, has changed the oil quality of the benchmark.[xvii] Additionally, the Troll oil field has an API gravity of 35.9 degrees, too low to be considered light.[xviii]

Figure 7: Quality, Ownership, and Monthly Flow of Oil Fields Related to Brent Crude

Field

Quality

Ownership Partners

Monthly Flow
as of March 2019
(in ‘000 Barrels)

Year Added
to the Brent Benchmark
Brent

Light, Sweet

Shell 50.00%
ExxonMobil 50.00%

2,400

1975
Forties/Buzzard

Light,
Not Sweet

Forties:
Apache 97.14%
ExxonMobil 2.61%
Shell 0.25%
Buzzard:
Nexen 43.21%
Suncor 29.89%
Chrysaor 21.73%
Dyas: 4.70%
Oranje-Nassau Energy: 0.46%

11,400

2002
Oseberg

Light, Sweet

Equinor 49.30%
Petoro 33.60%
Total 14.70%
ConocoPhillips 2.40%

3,600

2002
Ekofisk

Light, Sweet

Total 39.90%
ConocoPhillips 35.11%
Vår 12.39%
Equinor 7.60%
Petoro 5.00%

6,600

2007
Troll

Not Light, Sweet

Petoro 56.00%
Equinor 30.58%
Shell 8.10%
Total 3.69%
ConocoPhillips 1.62%

5,400

2018

 

Source: Thomson Reuters Monthly Production Data; https://www.cmegroup.com/rulebook/NYMEX/; https://www.platts.com/IM.Platts.Content/MethodologyReferences/Methodolo… http://factpages.npd.no/factpages/; http://www.offshore-technology.com/projects/brentfieldnorthseaun/; https://www.offshore-technology.com/projects/forties-oil-field-north-sea… http://www.nexencnoocltd.com/en/Operations/Conventional/UKNorthSea/Buzza… http://www.offshore-technology.com/projects/forties-oilfield-a-timeline/; https://www.ineos.com/businesses/ineos-fps/business/forties-blend-quality/; http://www.reuters.com/article/us-oil-platts-idUSKBN13R1PH; https://www.offshore-technology.com/projects/buzzard/; https://www.norskpetroleum.no/en/facts/field/oseberg/; http://www.conocophillips.no/our-norway-operations/greater-ekofisk-area/; https://www.offshore-technology.com/projects/troll-phase-three-developme…

Note:

1. Crude oil is considered “light” if it has an API gravity of between 37 and 42 degrees. Crude oil is considered “sweet” if it is low in sulfur content (< 0.42% by weight). These definitions come from the CME Group’s NYMEX Rulebook, although other sources use different ranges to classify light crude and sweet crude. Crude oil that does not qualify as light according to this definition is labeled as “not light” and crude oil that does not qualify as sweet according to this definition is labeled as “not sweet.” Crude oil in these categories may be referred to as “heavy” or “sour” in other sources, or they may be referred to as “medium sulfur” or “medium weight” if they fall between a source’s definition of “sweet” and “sour” or “light” and “heavy.”

2. Ownership percentages rounded to two decimal places.

3. The Forties Blend, transported via the INEOS-operated Forties Pipeline System, is made up of crude oil from over 70 fields. Buzzard is broken out separately since it is the largest component field and its inclusion starting in 2007 “altered the hydrocarbon characteristics of the Blend.” See https://www.ineos.com/businesses/ineos-fps/business/forties-blend-quality/.

One function of a benchmark is to provide an easy reference for buyers and sellers to price the wide variety of crudes with an agreed-upon differential to the benchmark. The differential, however, is dependent on the quality of the benchmark both in terms of volume and consistent quality. The potentially changing nature of Brent crude oil quality could jeopardize its role as the leading benchmark in many pricing contracts.

BFOE-T constitutes around 1 percent of world crude production,[xix] and there is concern that it does not provide a solid enough base for the Brent spot market to perform efficiently. Market and trading participants have recognized this change, and trading of the main futures contract of WTI and Brent has reversed. WTI futures trading volume has risen rapidly on NYMEX and has surpassed Brent on ICE. In January 2019, 30.0 billion WTI futures contracts were traded on NYMEX, compared to 17.3 billion Brent futures contracts on ICE.

Brent’s Delivery Mechanism

The price and the cash settlement mechanism of Brent futures are tied directly to the BFOE forward market, whose prices are assessed and published by price reporting agencies (e.g., Platts). This forward market consists of contracts that can be traded up to three months ahead of delivery. The forward contract assessment reflects the outright price of a cargo with physical delivery during the specified contract month for Brent, Forties, Oseberg, Ekofisk, and Troll crudes.

The closest-to-delivery contract for crude from BFOE-T basins is the spot market known as Dated Brent. Unlike other spot markets, Dated Brent has an inherent “forward” component to the contracts. On any given day, the contracts are written for the assessment of crude 10 days to one month forward from the contract date.

To enhance hedging opportunities, Brent traders can use the contract-for-difference (CFD) market. CFDs are swap contracts that track the difference between Dated Brent and BFOE forwards and allow traders to cope with the basis risk between the physical market and the financial risk-management market.

On the appointed day of delivery, sellers in the market will always load the product that is cheapest to deliver within allowable specifications.[xx] The cheapest-to-deliver concept became more important in 2007 with the introduction of the Buzzard field into the Forties stream. Because Buzzard tends to have lower-quality crude than other basins, it often became the cheapest crude that would fulfill contractual obligations.

Several iterations of quality price de-escalators and premiums were introduced over the years to compensate buyers in the event of low-quality deliveries, or to incentivize sellers to deliver higher-quality crude. Currently, Platts publishes a de-escalator for Forties Blend monthly, and Quality Premiums for Oseberg and Ekofisk are published for the current and following month. As the supply of BFOE-T basins declines overtime, more crude streams may be added to the deliverable basket. This will imply ever more complex and more frequent premium and discount calculations, depending not only on quality specifications, but also on freight differentials.

Price Report Agencies

Given that physical oil is traded by a few industry participants over the counter instead of on an exchange, the industry benefits from the increased transparency that price-reporting agencies provide by publishing assessed prices of the physical oil. Industry participants commonly trade physical and derivative products by reference to the prices reported by agencies such as Platts, Argus, and ICIS.

The main price-reporting agency for physical oil is Platts, which reports daily prices for over 200 global crude oil markets.[xxi] In order to calculate these daily prices, Platts compiles bids, offers, and transactions data submitted by physical oil market participants throughout each day as part of the Market-on-Close (MOC) process.[xxii] The last 30 minutes are considered the MOC window, which is an assessment period that determines an end-of-day value by using all available data from the day. Platts requires that participants declare their intention to post bids or offers in the MOC window before a cutoff point in the afternoon, which is 30 minutes before the close of the market.

A concern for regulators is whether the benchmark prices could be distorted by market participants, given that reporting transactions is optional. In March 2012, the International Organization of Securities Commissions (IOSCO), an umbrella body of market regulators, issued a report raising questions of whether further regulation was necessary.[xxiii] Similarly, from 2013 to 2015, the European Commission launched an investigation into the potential manipulation of oil price benchmarks.[xxiv] While this investigation did not lead to any convictions or fines, the European Union issued updated Benchmark Regulations in mid-2016.[xxv]

Conclusion

The Brent and WTI crude oil benchmarks have long battled for supremacy, and each faces different challenges. Scrutiny over Brent’s falling production in the North Sea has long been a concern, and WTI faces scrutiny for being in a landlocked location.

The views expressed in this article are solely those of the authors, who are responsible for the content, and do not necessarily represent the views of Cornerstone Research.

Endnotes

[i] “Crude Oils Have Different Quality Characteristics,” Today in Energy, U.S. Energy Information Administration, July 16, 2012, https://www.eia.gov/todayinenergy/detail.php?id=7110; WTI is both slightly lighter (American Petroleum Index (API) gravity of 39.6 vs. 38.3 degrees) and sweeter (0.24% vs. 0.37% of sulfur) than its Brent counterpart.

[ii] WTI is both slightly lighter (API gravity of 39.6 vs. 38.3 degrees) and sweeter (0.24% vs. 0.37% of sulfur) than its Brent counterpart.

[iii] “What’s Driving Global Oil Volumes Right Now,” MarketVoice, March 10, 2017, https://marketvoice.fia.org/issues/2017-03/whats-driving-global-oil-volu….

[iv] Total volumes for the North Sea fields Brent, Forties, Oseberg, and Ekofisk for July 2015, December 2015, and December 2016 were calculated by multiplying production rates by days of the month. Total volumes for June 2011, September 2011, October 2011, November 2011, October 2014, June 2015, July 2015, December 2015, December 2016, October 2017, and November 2017 for which data were unavailable were averaged from the latest prior and next earliest months’ total volumes.

[v] “About Seaway,” Seaway Crude Pipeline Company, http://seawaypipeline.com/.

[vi] “Seaway Begins Open Season,” Seaway Crude Pipeline Company Press Release, December 21, 2018, https://seawaypipeline.com/news/20181221PressRelease.pdf.

[vii] “Why the U.S. Bans Crude Oil Exports: A Brief History,” International Business Times, March 20, 2014, http://www.ibtimes.com/why-us-bans-crude-oil-exports-brief-history-1562689.

[viii] “Why the U.S. Bans Crude Oil Exports: A Brief History,” International Business Times, March 20, 2014, http://www.ibtimes.com/why-us-bans-crude-oil-exports-brief-history-1562689.

[ix] “OPEC, Allies Get Back on Track with Oil Cuts,” Bloomberg, May 17, 2019, https://www.bloomberg.com/graphics/opec-production-targets/.

[x] “Expanded Panama Canal Reduces Travel Time for Shipments of U.S. LNG to Asian Markets,” Today in Energy, U.S. Energy Information Administration, June 30, 2016, http://www.eia.gov/todayinenergy/detail.cfm?id=26892.

[xi] “U.S. Crude Production,” U.S. Energy Information Administration, https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_a.htm; “U.S. Exports by Destination,” U.S. Energy Information Administration, https://www.eia.gov/dnav/pet/pet_move_expc_a_EPC0_EEX_mbblpd_a.htm. For global oil production, see “BP Statistical Review of World Energy,” BP, June 2018, https://www.bp.com/content/dam/bp/business-sites/en/global/corporate/pdf….

[xii] “U.S. Oil Exports Double, Reshaping Vast Global Markets,” Wall Street Journal, June 7, 2017, https://www.wsj.com/articles/u-s-oil-exports-double-reshaping-vast-globa….

[xiii] “CVR Refining Oil Storage Sale Comes as Cushing Inventories Near 4-Year Low,” S&P Global Market Intelligence, September 18, 2018, https://www.spglobal.com/marketintelligence/en/news-insights/trending/tb….

[xiv] “Another Type of Crude Oil to be Included in Calculation of the Brent Price Benchmark,” Today in Energy, U.S. Energy Information Administration, March 10, 2017, https://www.eia.gov/todayinenergy/detail.php?id=30292.

[xv] “Shell Says Russia Oil Must Be Considered for Brent Benchmark,” Bloomberg, May 10, 2017, https://www.bloomberg.com/news/articles/2017-05-10/shell-says-russia-s-o… “Brent Benchmark Set for Revamp with Oil from Around the World,” Bloomberg, September 23, 2018, https://www.bloomberg.com/news/articles/2018-09-24/brent-benchmark-set-f….

[xvi] “Riding the Wave: The Dated Brent Benchmark at 30 Years Old and Beyond,” Platts, February 2018, p. 5, https://www.platts.com/IM.Platts.Content/InsightAnalysis/IndustrySolutio….

[xvii] “Forties Blend,” ExxonMobil, November 26, 2018, http://corporate.exxonmobil.com/en/company/worldwide-operations/crude-oi….

[xviii] “Crude Oil Assays,” Equinor, https://www.statoil.com/en/what-we-do/crude-oil-and-condensate-assays.html.

[xix] “Another Type of Crude Oil to Be Included in Calculation of the Brent Price Benchmark,” Today in Energy, U.S. Energy Information Administration, March 10, 2017,  https://www.eia.gov/todayinenergy/detail.php?id=30292; Commodity Research Bureau, The CRB Commodity Yearbook (Barchart.com, 2018).

[xx] That is, the cargo whose quality specification is the lowest deliverable and thus would yield the lowest spot market price outside the futures delivery mechanism.

[xxi] “Platts Global Alert – Oil,” S&P Global Platts, https://www.spglobal.com/platts/en/products-services/oil/global-alert-oil.

[xxii] “An Introduction to Platts Market-On-Close Process in Petroleum,” Platts, https://www.platts.com/IM.Platts.Content/aboutplatts/mediacenter/PDF/int….

[xxiii] “Functioning and Oversight of Oil Price Reporting Agencies – Consultation Report,” OICU-IOSCO, Technical Committee of the International Organization of Securities Commissions, March 2012, https://www.iosco.org/library/pubdocs/pdf/IOSCOPD375.pdf.

[xxiv] “Oil Traders Spared as EU Commission Drops Price-Rigging Probe,” Bloomberg, December 7, 2015, https://www.bloomberg.com/news/articles/2015-12-07/oil-traders-spared-as….

[xxv] “Regulatory Engagement and Market Issues ­– European Benchmark Regulation,” S&P Global Platts, https://www.spglobal.com/platts/en/about-platts/regulatory-engagement.

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