Tag: emissions

Treasury Proposes Clean Electricity Tax Guidance

On May 29, 2024, the Internal Revenue Service (IRS) and the Treasury Department released the pre-publication version of proposed guidance to implement “technology-neutral” clean electricity tax credits, including deeming certain technologies as per se zero-emitting and outlining potential methodologies for determining how other technologies—namely those involving combustion or gasification—could qualify as zero-emitting based on a lifecycle emissions analysis (LCA). The Clean Electricity Production Credit (45Y) and Clean Electricity Investment Credit (48E) were enacted in the Inflation Reduction Act (IRA) of 2022 and replace the current production and investment tax credits that are explicitly tied to certain types of renewable energy technologies.

Stakeholders have cited the 45Y and 48E credits as the most important driver of greenhouse gas (GHG) emission cuts possible from the IRA over the next decade. One study by the Rhodium Group found that the credits could reduce the power sector’s GHG emissions by up to 73 percent by 2035. The tax credits aim to give qualifying facilities the ability to develop technologies over time as they reduce emissions and offer longer-term certainty for investors and developers of clean energy projects. This proposed rule, when finalized, will be a critical driver for developers and companies allocating resources among different projects and investments.

The proposed guidance is scheduled to be published June 3, 2024 in the Federal Register, launching a 60-day comment period. A public hearing will be held August 12-13, 2024.

Proposed Guidance Details

Starting in Fiscal Year (FY) 2025 for projects placed into service after Dec. 31, 2024, 45Y provides taxpayers with a base credit of 0.3 cents (1.5 cents, if the project meets prevailing wage and apprenticeship requirements) per kilowatt of electricity produced and sold or stored at facilities with zero or negative GHG emissions. (These per kilowatt credit values are adjusted for inflation using 1990 as the base year.) Under 48E, taxpayers would receive a 6 percent base credit (30 percent, if the project meets prevailing wage and apprenticeship requirements) on qualified investment in a qualified facility for the year the project is placed in service. Both credits include bonus amounts for projects located in historical energy communities, low-income communities, or on tribal land; for meeting certain domestic manufacturing requirements; or for being part of a low-income residential building or economic benefit project. Direct pay and transferability are options for both credits. Both credits are in effect until 2032, when they become subject to a three-year phaseout.

Technologies recognized as per se zero-emissions in the guidance are wind, solar, hydropower, marine and hydrokinetic, nuclear fission and fusion, geothermal, and certain types of waste energy recovery property (WERP). The guidance also outlines how energy storage can qualify, including by proposing definitions of electricity, thermal, and hydrogen storage property.

A principal debate in the proposal is how to determine, using an LCA, whether certain combustion and gasification (C&G) technologies can qualify as zero-emitting.

The guidance includes a set of definitions and interpretations critical to implementation of the tax credits. For example, the proposed C&G definition includes a hydrogen fuel cell if it “produced electricity using hydrogen that was produced by an electrolyzer powered, in whole or in part, by electricity from the grid because some of the electricity from the grid was produced through combustion or gasification.” The proposed C&G definition would also include both biogas- and biomass-based power, but eligibility depends on the LCA results; for biomass, the guidance seeks comment on what spatial and temporal scales should apply and how land use impacts the LCA.

The guidance states that the IRS intends to establish rules for qualifying facilities that generate electricity from biogas, renewable natural gas, and fugitive sources of methane. The guidance says that Treasury and the IRS “anticipate” requiring that, for such facilities, the gas must originate from the “first productive use of the relevant methane.”

The proposed C&G definition allows for carbon capture and storage (CCS) that meets LCA requirements. However, the IRA does not allow credits to go toward facilities already using certain other credits, including the relatively more generous section 45Q credits for CCS.

Specifically, there are seven other credits that cannot be used in combination with a 45Y or 48E credit: 45 (existing clean electricity production credit); 45J (advanced nuclear electricity credit); 45Q (CCS); 45U (zero-emission nuclear credit); 48 (existing clean electricity investment credit); for 45Y, 48E (new clean electricity production credit); and for 48E, 45Y (new clean electricity investment credit).

The guidance proposes beginning and ending boundaries for LCAs, stating “the starting boundaries would include the processes necessary to produce and collect or extract the raw materials used to produce electricity from combustion or gasification technologies, including those used as energy inputs to electricity production. This includes the emissions effects of relevant land management activities or changes related to or associated with feedstock production.” Another topic in the guidance is the use of carbon offsets to reach net-zero qualification status, with the proposal seeking comment on boundaries: “offsets and offsetting activities that are unrelated to the production of electricity by a C&G Facility, including the production and distribution of any input fuel, may not be taken into account” by an LCA. The guidance also includes rules on qualified interconnection costs in the basis of a low-output associated qualified facility, the expansion of a facility and incremental production, and the retrofitting of an existing facility.

The guidance describes the role of the Department of Energy (DOE) in implementing the tax credits. Any future changes to technologies designated as zero-emitting or to the LCA models must be completed with analyses prepared by DOE’s national labs along with other technical experts. Facilities seeking eligibility may also request a “provisional emissions rate,” which DOE would administer with the national labs and experts “as appropriate.”

Next Steps

As noted above, the proposed guidance is scheduled to be published June 3, 2024 in the Federal Register, launching a 60-day comment period for interested parties to make arguments and provide evidence for changes they would like to see before the rule becomes final. A public hearing will be held August 12-13, 2024. The Treasury Department in consultation with interagency experts plans to carefully review comments and continue to evaluate how other types of clean energy technologies, including C&G technologies, may qualify for the clean electricity credits.

© 2024 Van Ness Feldman LLP
For more news on Clean Energy Tax Credits, visit the NLR Environmental, Energy & Resources section.

Red States Move to Penalize Companies That Consider Climate Change When Making Investments

A number of conservative-leaning states, particularly those with a significant fossil fuel industry (e.g., Texas, West Virginia), have begun implementing polices and enacting laws that penalize companies which “pull away from the fossil fuel industry.”  Most of these laws focus on precluding state governmental entities, including pension funds, from doing business with companies that have adopted policies that take climate change into account, whether divesting from fossil fuels or simply considering climate change metrics when evaluating investments.

This trend is a troubling development for the American economy.  Irrespective of the merits of the policy, or fossil fuel investments generally, there are now an array of state governments and associated entities, reflecting a significant portion of the economy, that have adopted policies explicitly designed to remove climate change or other similar concerns from consideration when companies decide upon a course of action.  But there are other states (typically coastal “blue” states) that have enacted diametrically opposed policies, including mandatory divestments from fossil fuel investments (e.g., Maine).  This patchwork of contradictory state regulation has created a labyrinth of different concerns for companies to navigate.  And these same companies are also facing pressure from significant institutional investors, such as BlackRock, to consider ESG concerns when making investments.

Likely the most effective way to resolve these inconsistent regulations and guidance, and to alleviate the impact on the American economy, would be for the federal government to issue a clear set of policy guidelines and regulatory requirements.  (Even if these were subject to legal challenge, it would at least set a benchmark and provide general guidance.)  But the SEC, the most likely source of such regulations, has failed to meet its own deadlines for promulgating such regulations, and it is unclear when such guidance will be issued.

In the absence of a clear federal mandate, the contradictory policies adopted by different state governments will only apply additional burdens to companies doing business across multiple state jurisdictions, and by extension, to the economy of the United States.

“Republicans and right-leaning groups fighting climate-conscious policies that target fossil fuel companies are increasingly taking their battle to state capitals. Texas, West Virginia and Oklahoma are among states moving to bar officials from dealing with businesses that are moving to ditch fossil fuels or considering climate change in their own investments. Those steps come as major financial firms and other corporations adopt policies aligned with efforts to reduce greenhouse gas emissions.”

Article By Jacob H. Hupart of Mintz

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

©1994-2022 Mintz, Levin, Cohn, Ferris, Glovsky and Popeo, P.C. All Rights Reserved.

EPA Proposes Affordable Clean Energy Rule

On August 21, 2018, the Environmental Protection Agency (EPA) issued a proposed rule pursuant to section 111(d) of the Clean Air Act (CAA) that would establish emission guidelines for states to develop plans to limit carbon dioxide (CO2) emissions from existing fossil-fired power plants.  The proposed Affordable Clean Energy (ACE) rule would replace the 2015 Clean Power Plan (CPP), which EPA is proposing to repeal (in a separate rulemaking) on the grounds that the CPP exceeded the agency’s authority under the CAA.

Core elements of the proposed ACE rule include: (1) a determination of the best system of emission reduction (BSER) for CO2 emissions from coal-fired power plants; (2) a list of “candidate technologies” states can use when setting CO2 performance standards for affected plants; (3) a new preliminary applicability test for determining whether a physical or operational change made to a power plant may be a “major modification” triggering New Source Review (NSR); and (4) new implementing regulations for establishing emission guidelines under CAA section 111(d).

Section 111(d)

EPA is proposing the ACE rule pursuant to section 111(d) of the CAA.  This section directs EPA to promulgate regulations establishing a federal-state process for setting standards of performance limiting emissions from existing sources for pollutants not otherwise regulated in other specified sections of the CAA.  Implementing section 111(d) is a three-step process.  First, EPA issues a “guideline” for states to use in developing compliance plans that include standards of performance for stationary sources within a particular source category.  The guideline identifies what EPA determines is the BSER for the relevant sources within the source category.  Second, each state submits a plan to EPA that includes standards of performance for the covered sources in the state.  Third, EPA approves or disapproves of the state plans.  If a state fails to submit an approvable plan, the CAA requires EPA to impose a federal plan.

Proposed BSER Determination

EPA is proposing to define BSER for CO2 emissions from existing coal-fired power plants as heat-rate efficiency improvements based on a range of “candidate technologies.”  This “inside the fence” BSER determination reflects a different approach than what was used in the CPP.  The CPP determined the BSER for power plants based on reductions achievable not only through inside-the-fence measures such as heat rate improvements but also through shifting of generation from higher-emitting to lower-emitting or zero-emitting plants.  As noted above, EPA has proposed to find that such an “outside-the-fence” approach to determining BSER exceeds the agency’s authority under the CAA.

EPA has identified a list of the “most impactful” heat rate improvement measures.  EPA is proposing that this list serve as the “candidate technologies” or “checklist” of BSER technologies, equipment upgrades, and best operating and maintenance practices for coal-fired power plants.  These candidate technologies are:

  • Neural Network/Intelligent Sootblowers

  • Boiler Feed Pumps

  • Air Heater and Duct Leakage Control

  • Variable Frequency Drives

  • Blade Path Upgrade (Steam Turbine)

  • Redesign/Replace Economizer

  • Improved Operating and Maintenance Practices

States would consider the above technologies in establishing standards of performance for existing coal-fired power plants.  EPA is proposing that performance standards will set a specific allowable emission rate expressed on a pound CO2 per MWH-gross rate for each affected unit based on the application of the appropriate candidate BSER technologies to each unit.

EPA explains in the proposed rule that it does not have sufficient information to make a BSER determination with respect to heat rate improvements at natural gas-fired simple‑cycle turbines or combined cycle turbines.  The agency is soliciting comment on this issue.  Previously, EPA determined that heat rate improvement measures at natural gas‑fired combustion turbines would not be considered BSER because such measures cannot provide meaningful reductions at reasonable cost.

State Compliance Plans

The proposed rule would provide each state with broad discretion in establishing specific performance standards for particular plants.  The proposal also allows state plans to rely on emission averaging and trading among affected coal‑fired units at a particular plant.  However, EPA has proposed that state plans should not be allowed to incorporate averaging and trading among different plants, such as a state-wide or interstate cap-and-trade program.  Nor will any credit be given for CO2 emissions reductions achieved through increased generation of renewable energy or gas-fired generation not covered under the section 111(d) regulatory program.  The proposed rule explains that such an approach would be inconsistent with EPA’s proposed “inside-the-fence” interpretation of BSER under section 111.

Permitting Under NSR Program

EPA is proposing revisions to the NSR permitting program to make it easier for power plants to adopt heat rate improvements without triggering NSR obligations.  The NSR program is a preconstruction permitting program.  An NSR permit is required not only before construction of a new major stationary source; it is also required before modifying an existing major source if the modification will result in a significant emissions increase of any NSR-regulated pollutant.  Projects that cause a significant increase in annual emissions may trigger onerous NSR permitting requirements, which include installation of state-of-art emission control technologies, prescriptive air quality modeling, and extensive public notice and comment procedures.

To avoid widespread triggering of NSR permitting requirements from heat rate improvement projects undertaken by affected coal‑fired plants, EPA is proposing to amend the NSR regulations to include an hourly emissions increase test.  Under the proposed revisions, a non-excluded physical or operational change to an electricity generating unit would only trigger NSR if the change resulted in an increase in the unit’s maximum hourly emissions rate under procedures proposed in the ACE rule, as well as a significant emission increase in annual emissions under the current NSR regulations.

As drafted, the proposed maximum hourly emission increase test would be available to any electricity generating unit, including natural gas-fired units that would not be subject to regulation under section 111(d).

States with approved NSR programs would have the option but would not be required to adopt the hourly emission increase test ultimately promulgated as part of the NSR provisions in their SIPs.  For those states with delegated NSR programs that are acting on behalf of EPA, the NSR permitting process would have to include any changes that are ultimately made to the federal NSR provisions as they would be administering the federal program.

EPA is proposing that the potential revisions to the NSR permitting program are severable from the rest of the ACE rule.

Implementing Regulations for Emission Guidelines under Section 111(d)

The proposal revises the general implementing regulations for section 111(d) that govern how EPA issues emission guidelines, and how and when states develop and submit their plans.  These changes would apply for all future section 111(d) rules.  Proposed changes include the following:

  • Timing:  The proposal updates timing requirements regarding submission of state plans and EPA action on those state plans.

    • State submissions:  EPA is proposing to provide states three years to develop state plans.  The existing implementing regulations provide nine months.

    • EPA action:  The proposal would allow EPA 12 months to act on a complete state plan submittal.  The existing implementing regulations provide four months.

    • Federal plan:  The proposal would allow EPA two years to issue a federal plan after a finding of a state’s failure to submit an approvable plan.  The existing implementing regulations provide six months.

  • Criteria for state plans:  The proposal has completeness criteria for state plans that include administrative materials and technical support for state implementation of the plan.  EPA would have six months to determine completeness and would make that determination by comparing the state’s submission against the completeness criteria.

  • Variance provisions:  The proposal provides greater flexibility to states to adopt plans that include variances from the EPA guidelines that will allow, among other things, states to take into account the remaining useful life of the unit and other relevant factors in establishing a performance standard for a particular affected unit.

Next Steps

EPA will take comment on the proposal for 60 days after publication in the Federal Register and will hold at least one public hearing.  Depending on the exact date of Federal Register publication, this means comments will be due to EPA sometime in late October 2018.

Impacts of EPA Proposal

According to EPA, the proposed ACE rule would reduce the compliance burden by up to $400 million per year when compared to the CPP.  EPA estimates that the ACE rule could reduce overall 2030 CO2 emissions by up to 1.5% from projected levels without the CPP.

 

© 2018 Van Ness Feldman LLP
This post was written by Kyle W. Danish and Stephen C. Fotis  of Van Ness Feldman LLP.

Curbing Greenhouse Gas (GHG) Emissions – Good for the Environment, Bad for Investors?

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On June 2, 2014, EPA issued a proposed rule to control greenhouse gas emissions (GHGs) from the electric power generation sector of the United States. EPA’s goal is to obtain a reduction of GHG emissions in 2030 from this sector of 30% from the baseline year 2005. The 2005 baseline allows EPA to take credit for GHG emission reductions that have occurred since that time without any regulatory obligation. The proposal establishes GHG emission targets for each State (expect the District of Columbia and Vermont who do not have goals under the rule). Interim emission targets must be obtained in the 2020-2029 timeframe with final targets obtained by 2030.

The proposal does not suggest any particular emission limit on particular plants, but imposes the obligation on the States to derive a plan to achieve the reductions. The only penalty for noncompliance in the proposal is that EPA would impose an EPA-developed plan within the State if it fails to submit an approvable plan. While EPA has not dictated any particular approach a State may employ, the proposal favors a cap and trade or carbon tax system as the primary manner to obtain GHG emissions reductions.

So here are the two burning questions from the perspective of investors. First, will this rule actually survive in anywhere near this form?  Second, when will affected power projects need to start ramping up investment in order to comply with the rule, i.e., when should investors start to worry about financial capacity?

In terms of a “review for reality,” many industry experts suggest that it is nearly impossible to obtain the proposed 6% efficiency improvement at existing coal-fired power plants without major capital improvements, which could require complex Clean Air Act permitting under other provisions of the law. Other goals can only be achieved through substantial purchases of carbon credits (i.e., offsets) or the implementation of technologies that haven’t yet been proven to be commercially viable. (You’ve likely heard the aspirations to develop carbon capture and sequestration.) EPA also assumes that natural gas-fired power plants will be running at 70% capacity year-round, which may be difficult to achieve in practice. Finally, EPA assumes that energy efficiency improvements at the consumer level will be obtained at a rate of 1.5% every year until 2030 – an ambitious goal.

In terms of a “review for timing,” this is only the beginning of a very long process. After the usual rounds of public comment, EPA has targeted issuance of the final rule by June 1, 2015. Then the lawsuits will start. Then a new President with his/her own views will take office. Plus, even under the EPA’s own best case scenario, the proposed rule allows states until June 2016 to submit plans, with the potential for extension to June 2017. Once a state submits a plan, EPA must approve or disapprove it through notice and comment rulemaking. The proposal allows for EPA to complete the review of the plans within 12 months of the state plan submittal. If a state doesn’t submit a plan or EPA disapproves the plan, EPA must make a plan for the state. State plans must begin to meet an interim goal in 2020 and must achieve their final goal by 2030. Plus, State plans and EPA approval/disapproval present a separate source of litigation and associated delay.

So no need for panic dumping of carbon-intensive investments just yet, but keeping an eye on the process would be wise, including consideration of whether, if your industry investments are large enough, you should participate in, or form/join a group to participate in, the comment-making phase plus working with members of Congress. The earlier the involvement, the greater the opportunity to help shape the results.

Article By:

Jeffrey R. Holmstead
Richard Alonso
Jason B. Hutt
Evan D. Flaschen
Of:
Bracewell & Giuliani LLP