Searching for opportunities in the Inflation Reduction Act
Companies are scrambling to assess the effects of the Inflation Reduction Act on their projects.
The tax equity market will look different. Tax credits after this year can be sold for cash.
Tax benefits on some 2022 projects will be higher than the developers expected.
Bidders to supply electricity or buy projects are reworking bids.
The Internal Revenue Service rushed out guidance on new electric vehicle tax credits the same day that President Biden signed the bill, suggesting that guidance on new wage and apprentice requirements may be out sooner than expected. It will trigger a requirement to pay construction workers the same wages that are paid on federal construction jobs and use qualified apprentices for 10% to 15% of total labor hours on projects that are not under construction within 59 days after the guidance is issued.
Construction may slow for the rest of this year on projects that will qualify for higher tax credits if they are not completed until next year. For example, bonus tax credits may be available, depending on the location and the amount of US-made components, but only on projects placed in service in 2023 or later. New tax credits for batteries and equipment to make clean hydrogen and renewable natural gas, and higher tax credits for installing carbon capture equipment, require delaying completion until next year.
Manufacturers will look to do more manufacturing in the United States. The government will pay part of the cost to make components for solar, wind and storage projects and lithium, graphite and other basic minerals. Manufacturers will qualify for tax credits on each such component or mineral produced and sold during the period 2023 through 2032. They can apply to the Internal Revenue Service for cash “refunds” of the tax credits for up to five tax years. The articles must be made in the United States and sold to an unrelated party.
The dynamics of some contract negotiations will shift.
Some manufacturers who were demanding premiums to sell articles made in the United States to help developers earn bonus credits for using domestic content may find the tables turned now that they qualify for large tax credits.
Utilities that were willing to renegotiate power contracts to accommodate higher-than-expected construction costs due to tangled supply chains and labor shortages may now look to developers to temper their requests.
Batteries will no longer have to be coupled with solar projects in order to qualify for tax credits. This will lead to a change in how power contracts and tolling agreements for use of batteries will be written for future projects. Solar companies will no longer have to be careful to avoid charging during the first five years from the grid for new batteries placed in service after this year.
Solar companies will have to rethink whether to claim production tax credits on the electricity output over 10 years rather than an investment tax credit in the year projects are placed in service. Many developers retained the option in tax equity papers this year to move to production tax credits if the option became available. Tax equity investors for the most part agreed to take a good-faith look at restructuring, but without making a firm commitment.
Some wind and solar projects completed after this year will qualify for production tax credits on the electricity output and an investment tax credit on the battery in cases where the generating equipment and battery are considered separate “facilities.”
The race to get more projects under construction before the IRS issues guidance on the new wage and apprentice requirements promises to create a year-end traffic jam in front of main power transformer, nacelle and other vendors.
Municipal utilities, community choice aggregators, rural electric cooperatives, the Tennessee Valley Authority and Indian tribes may rethink whether to own renewable energy projects directly rather than buy electricity. The bill lets them receive cash “refunds” of tax credits from the IRS on projects they own.
Some developers may turn power contracts with such entities into leases to pass through investment tax credits that the lessee may be able to apply to the IRS to have refunded in cash. This structure may require IRS confirmation. It does not work for projects on which production tax credits will be claimed on the electricity output or that will be placed in service before next year.
More carbon capture transactions will become economic. The market will expand focus from the ethanol and fertilizer plants where the economics worked best to the next low-hanging fruit.
Some carbon capture transactions already in process will have to be reworked. The federal government puts a lot of money on the table in the form of carbon capture credits. The deal structure is a function of who needs what share and what labels to put on the money transfers. The higher tax credits may require shifts in the money flows, particularly in projects with low-carbon fuel standard, or LCFS, credits.
Offshore wind has become a better bet. Developers now have the option to claim production tax credits on the electricity output. They will also have until sometime in the 2030s to start construction to qualify for tax credits at full rates and another 10 years after that to finish construction, giving them a runway into the 2040s to build new projects.
The Inflation Reduction Act is 728 pages, but it distills to a few basic points.
It restores federal tax credits to the full rate for new renewable energy projects completed in 2022 or later.
The full rate is a 30% investment tax credit or production tax credits of $26 a MWh on the electricity output for 10 years. Production tax credits are adjusted annually for inflation. A new rounding convention for production tax credits will add another $1.50 per MWh for projects completed in 2022 and possibly for projects that are completed in the next two years or that start construction by the end of 2024, depending on the inflation rate.
The tax credits will remain at this level at least into the early 2030s.
The ITC could reach as high as 50% — in some cases even 70% — depending on the location of the project and whether it uses domestic content, but only for projects that are completed in 2023 or later. PTCs would increase as well.
The tax credit amounts would start to phase down after annual greenhouse gas emissions from US electricity generation fall by at least 75% from 2022 levels, but not before 2032.
Projects starting construction two years after the phase down starts would qualify for tax credits at 75% of the full rate. Projects starting construction three years after would qualify for tax credits at 50% of the full rate. Thus, for example, if the phase out trigger is reached in 2032, projects starting construction in 2033 would still qualify for tax credits at the full rate.
The bill provides a new 30% investment tax credit for standalone storage. Pumped-storage hydroelectric projects, which are essentially large water batteries, qualify for this tax credit as standalone storage.
There are also new tax credits for making clean hydrogen or renewable natural gas and for manufacturers who make components for wind, solar and storage projects and basic minerals.
Solar developers will have the option to claim PTCs instead of ITCs on projects placed in service in 2022 or later.
Tax credits for new transmission lines failed to make the cut. There was a feeling on Capitol Hill that economics are less of an impediment to building new transmission lines than inability to get permits. The Senate majority leader, Chuck Schumer (D-NY), agreed to a separate side deal on permitting reform with Senator Joe Manchin (D-WV) as part of the price for Manchin’s support. Democrats will attempt to put the permitting deal through the Senate by folding it into a must-pass bill to keep the federal government operating past the fiscal year end on September 30. (For more details about the possible permitting reforms, see the “Environmental Update” in the August 2022 NewsWire.)
Starting next year, companies will be allowed to sell most energy-related tax credits to other companies without having to resort to complicated tax equity structures. The seller will not have to report the cash purchase price as income.
The buyer must pay cash. It cannot be related to the seller.
The seller can sell all or part of its tax credits. It can decide each year how much to sell.
In cases where a project is owned by a partnership, the partnership sells the tax credits.
The bill also allows most energy-related tax credits that a company cannot use to be carried back three years to get refunds of taxes paid in the past and to carry any remaining tax credits forward for up to 22 years (rather than the current 1-year carryback and 20-year carryforward). This change does not take effect until 2023. Tax credits that are carried backward or forward cannot be sold.
The renewable energy industry had been hoping for a “direct-pay” alternative to tax credits where companies could be paid the full cash value of the tax credits by the IRS under a tax refund mechanism.
A narrow direct-pay provision is in the bill, but with the exception of three types of tax credits, it is limited to tax-exempt entities, state and local governments, rural electric cooperatives, the Tennessee Valley Authority, Indian tribes and Alaskan native claims corporations.
The three types of tax credits that real taxpayers can ask the IRS to pay them in cash are section 45Q credits for capturing carbon emissions, production tax credits for making clean hydrogen and production tax credits for “advanced manufacturing” of components for wind, solar and storage projects and basic minerals.
It will probably be better to wait for an IRS refund for 100% of the credit amount in cash rather than sell these three types of tax credits to third parties for less than the full credit amount. However, direct payments to private parties would only be made for one to five years of credits.
Tax equity will still remain of interest to many developers, particularly those claiming investment tax credits. The tax equity market continued to function during the period 2009 through 2016 when developers had the option to receive cash payments in lieu of tax credits directly from the US Treasury.
The tax basis used to calculate tax benefits can be stepped up to fair market value in a tax equity transaction unlike a direct tax credit sale.
There will be longer time lags to get IRS refunds than for the Treasury cash grants. A developer could apply for a cash grant immediately after a project went into service. Applications for IRS cash “refunds” will lag by a year. The application is filed with the tax return for the year the project went into service.
Developers who want to monetize depreciation will have to do so through tax equity transactions. The tax savings from 5-year MACRS depreciation are worth 14¢ per dollar of capital cost on top of at least 30¢ per dollar of capital cost for tax credits.
On the other hand, tax credit sales will put less strain on cash flow. In most solar partnership flip transactions, project companies are sold to tax equity partnerships near the end of construction. The developer must contribute part of the capital the partnership requires to pay the purchase price. No such contributions would be required in a tax credit sale.
There are tight deadlines to close tax equity deals involving investment tax credits. There will not be the same tight deadlines in tax credit sales.
The direct-sale market will take time to develop.
Direct sales could democratize access to capital in theory. In practice, smaller developers are likely to have trouble finding buyers because buyers will want creditworthy sellers who can stand behind tax indemnities in the event the tax credits are not as promised. In 1981 and 1982 when the US had a version of tax credit sales called “safe-harbor leasing,” companies with poor credit had to buy insurance from Lloyd’s syndicates to backstop the indemnities.
Tax credit sales may revive interest in paying developer fees that can add to tax basis for calculating tax credits. Interest in such fees waned after Invenergy lost two court cases in which the government successfully disallowed developer fees on two wind projects. (For more detail, see “California Ridge: Developer Fees Struck Down — Again” in the May 2020 NewsWire.)
The bill gives the IRS authority to collect 120% of any “excessive payment” where an inappropriately high tax basis is used in a tax credit sale.
The tax credits in the Inflation Reduction Act come with two sets of fine print.
Project owners must make sure their construction contractors pay laborers and mechanics the same Davis-Bacon wages that are paid on federal construction jobs not only during construction, but also on later repairs and improvements during the period PTCs are claimed or any ITC claimed remains subject to recapture.
The contractor must also use qualified apprentices for 10% to 15% of total labor hours during the same period.
These requirements will not apply to any project on which construction starts no later than 59 days after the IRS issues guidance to implement the wage and apprentice requirements or that is less than one megawatt AC in size.
The IRS started working on the wage and apprentice guidance at the urging of labor unions before the bill was signed.
Possible 50% ITC
The bill has domestic content requirements that are both a carrot and a stick.
The carrot is the ability to claim as much as an extra 10% investment tax credit (or a 10% increase in PTC amount) by using domestic content.
Domestic content means all steel, iron and manufactured products must be produced in the United States. Manufactured products would be considered US made if at least 40% of all the manufactured products used in the project are US made. The percentage would increase for projects that start construction after 2024 and eventually reach 55% for projects with 2027 or later construction-start dates. The percentage for offshore wind projects would start at 20% and increase over time, reaching 55% for projects with 2028 or later construction starts.
The stick is inability to receive a direct cash payment in lieu of tax credits from the IRS. However, since the bill narrowed direct pay essentially to tax-exempt and government entities, this is not much of a stick, other than for carbon capture and hydrogen projects.
Projects in “energy communities” will qualify for as much as another 10% ITC (or another 10% increase in PTC amount).
Energy communities are brownfield sites and two other locations.
One is metropolitan or non-metropolitan statistical areas that have, or had at any time after 2009, at least 0.17% direct employment or at least 25% local tax revenues related to “extraction, processing, transport, or storage of coal, oil, or natural gas” and have an unemployment rate at or above the national average.
The other location is census tracts where a coal mine closed after 1999 or a coal-fired generating “unit” retired after 2009 and any directly-adjoining census tract.
Community solar projects qualify potentially for two special benefits.
Power projects with maximum net outputs of up to five megawatts AC will be able to claim investment tax credits on the cost of any gen-tie line paid for by the generator and owned by the utility and any network upgrade costs paid by the generator that the utility will not repay through transmission credits.
The bill allows an extra 20% investment tax credit to be claimed on solar and wind facilities with maximum net outputs of less than five megawatts AC that provide at least half of the “financial benefits of the electricity produced” to low- and moderate-income households. An extra 10% ITC could be claimed on small such projects in low-income communities or on Indian land. Anyone with a project in either category would have to apply to the IRS for an allocation of “environmental justice solar and wind capacity limitation.”
The IRS will award 1,800 MW of such limitation in each of 2023 and 2024. Any projects given awards must be completed within four years after the award.
Since the tax credits can be stacked, this could get a project to as high as a 70% ITC.
The bill makes it easier for storage projects to contract with tax-exempt or government entities without losing the investment tax credit and accelerated depreciation. Any project leased in substance to such an entity does not qualify for such tax benefits. A safe harbor that ensures currently that power contracts with tax-exempt and government entities are “service contracts” rather than leases would be extended to storage projects.
The bill will let all storage facilities be depreciated using five-year MACRS depreciation.
It also increases and liberalizes section 45Q tax credits for carbon capture and allows a tax credit of up to $3 kilogram for producing clean hydrogen.