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Eliminate Immediate Deduction for Intangible Drilling Costs

The budget legislation eliminates the provision that conforms to Section 263(c) of the Internal Revenue Code to allow an immediate deduction for up to 70% of intangible drilling costs for oil and gas wells and geothermal wells (100% for independent oil producers). The repeal would apply to costs incurred on or after January 1, 2024. Intangible drilling costs include surveys, ground clearing, drainage, repairs, and other such work. Producers must amortize the remaining 30% of these costs over five years.

The immediate deduction is designed to encourage investment in oil production. The repeal of this tax benefit will likely further discourage investment from independent producers. California has conformed to federal tax law on this provision since 1987.

Percentage Depletion Rules for Fossil Fuels

The legislation also repeals the calculation of the deduction for depletion of natural resources as a percentage of gross income from the property (15% for independent producers). This applies to specified natural resources, including coal, oil, oil shale, and gas and apples to tax years beginning on or after January 1, 2024. California has conformed to federal law on this provision since 1993. The deduction of a fixed percentage of gross income is higher than the normal cost-depletion method.

The legislation also eliminates the statute that allows the state to not conform to federal law that prevents refiners with average daily refinery runs of more than 75,000 barrels for a tax year from calculating a depletion deduction as a percentage of gross income.

Enhanced Oil Recovery Costs Credit

Lastly, the budget legislation eliminates the 5% tax credit for qualified enhanced oil recovery (EOR) costs that applies to small, independent oil producers. This benefit applies only when oil prices are low. This repeal is effective December 1, 2024.

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The governor’s budget summary refers to these tax provisions as “subsidies” and states that repealing them would increase state revenues by $22 million in 2024-25 and by $17 million a year in subsequent years. The proposals come along with proposed spending cuts and delays to address the state’s $37.9 billion deficit. (See Newsom’s Proposed Budget Cuts and Delays Spending on Key Climate Programs.)

Immediate Deduction for Intangible Drilling Costs

The budget would eliminate the provision that allows oil producers to deduct up to 70% of intangible oil and gas drilling costs immediately. These costs include such work as surveys, ground clearing, drainage, and repairs. The remaining 30% of these costs is required to be amortized over five years. Independent oil producers can deduct 100% of intangible drilling costs immediately.

California, conforming with federal tax law, has allowed the immediate deduction of these costs since 1987. This immediate deduction benefit is designed to encourage investment in oil production, given the risky nature of oil and gas exploration and production. The repeal of this tax benefit will likely further discourage investment from independent producers.

Percentage Depletion Rules for Fossil Fuels

The budget would also eliminate the allowance to deduct a fixed percentage (15% for independent producers) of gross income that is higher than the normal cost-depletion method when it comes to resource depletion of mineral and other natural resources. California is in conformity with federal law and has allowed this benefit since 1993.

Enhanced Oil Recovery Costs Credit

The budget would also eliminate the benefit that allows small, independent oil producers a tax credit of 5% of their qualified enhanced oil recovery (EOR) costs if the reference price of domestic crude oil exceeds a specified threshold for the preceding year. Taxpayers who are retailers of oil or natural gas and those who are refiners of crude oil whose daily output exceeds 50,000 barrels are not eligible for the credit. This benefit applies only when oil prices are low and has not applied recently.

Pressure from Environmental and Climate Groups

The administration’s proposals were more limited than those pushed by a coalition of environmental and climate groups. In a letter to Newsom and legislative leaders, the coalition called for eliminating a broader range of business tax credits:

• “Water’s Edge Election”

• Research and Development Credit

• Accelerated Depreciation of Research and Experimental Costs

• Percentage of Depletion of Mineral and Other Natural Resources

• Intangible Drilling Cost Deduction

The group also requested that the state Department of Finance identify “all current tax expenditures both specifically for the oil and gas industry and broader corporate tax expenditures that the oil and gas industry benefit from and utilize.” The group’s main focus is on the state’s “Water’s Edge Election,” which allows for companies to be taxed by the state only on income attributed to the state.

On March 28, 2023, Governor Gavin Newsom signed into law SBX1-2, which gives the California Energy Commission (CEC) new powers to monitor the gasoline market and impose penalties on refiners who charge more than a maximum margin for refining gasoline.

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The bill also imposes new reporting requirements on pipelines, port operators, and refiners. (For additional details see: Legislation to Monitor Gasoline Prices and Impose Penalties on Refiners Passes Senate.)

The legislation, which was approved 58-19 in the Assembly and 30-8 in the Senate, takes effect on June 26, 2023. The legislation follows Newsom’s March 15, 2023 amended proposal for an oil profits penalty. (see Newsom Amends Oil Profits Penalty Proposal.)

The governor’s office described the legislation as the “strongest state-level oversight and accountability measures on Big Oil in the nation – bringing transparency to California’s oil and gas industry, shining new light on the corporations that have for decades operated in the shadows while ripping families off and raking in record profits.”

Legislation to create a watchdog to monitor gasoline prices with the authority to impose a penalty on refiners passed the California State Senate March 23, 2023. The bill, SBX1-2, would also impose new reporting requirements on pipelines, port operators, and refiners. The legislation follows Newsom’s March 15, 2023 amended proposal for an oil profits penalty. (see Newsom Amends Oil Profits Penalty Proposal.)

The bill “represents a major milestone in our efforts to drive the oil industry out of the shadows and ensure they play by the rules,” Newsom said in a statement earlier in the week. “This represents some of the strongest and most effective transparency and oversight measures in the country, and the penalty would root out price gouging.”

Division of Petroleum Market Oversight

The legislation would establish the Division of Petroleum Market Oversight within the California Energy Commission (CEC) with a director appointed by the governor and subject to Senate confirmation. The division would operate with authority independent of the CEC.

The division would provide guidance and recommendations to the governor and the CEC on issues related to transportation fuels pricing and “transportation decarbonization.” The bill would establish the Independent Consumer Fuels Advisory Committee to advise the CEC and the division.

The new division would have access to new information required to be reported by refiners (see below) along with subpoena power to compel refiners to produce additional data and records that could show patterns of misconduct or price manipulation. It would also have the authority to refer violations of the law to the California Attorney General’s Office for prosecution.

The legislation also authorizes the CEC to begin a rule-making process to create a penalty structure for price gouging. The structure would impose a civil penalty on refiners who charge more than a maximum allowable margin for the price of gasoline.

Reporting Requirements for Pipeline and Port Operators

The bill would impose new reporting requirements on pipeline operators and operators of ports through which refined gasoline is imported. The bill would require pipeline and port operators to report annually their capacities for all pipelines and ports used to transport refined gasoline; all importers of refined products and renewable fuels via marine vessel would be required to submit reports to the CEC; non-refiners that commercially trade in gasoline, gasoline blending components, diesel fuel, or renewable fuel inventory would submit weekly reports to the commission; refiners and non-refiners that consummate spot market transactions would submit a daily report to the CEC containing certain information for each transaction occurring in the preceding day; and refiners would report planned and unplanned maintenance activities.

Reporting Requirements for Refiners

This bill would require operators of refineries to report additional information, including the net gasoline refining margin per barrel of gasoline sold in that month. The CEC would be required to post on its internet website certain information related to the net gasoline refining margin.

Annual Report to the Legislature

This bill would require the CEC, in cooperation with the California Department of Tax and Fee Administration, to submit an annual report to the legislature that reviews the price of gasoline in California and its impact on state revenues for the previous calendar year. The CEC would be authorized to request from any person certain records to facilitate the report or to assist the commission.

This bill would also require the CEC, on or before January 1, 2024 and every three years thereafter, to submit an assessment to the governor and the legislature on ensuring a reliable supply of affordable and safe transportation fuels in California. It would require the CEC to use reasonable means necessary and available to seek and obtain information from any sources for purposes of preparing the assessment and would authorize the commission to impose a civil penalty if a person fails to timely provide information necessary for preparing the assessment. The CEC and the California Air Resources Board (CARB) would be required to prepare a Transportation Fuels Transition Plan on or before December 31, 2024.

Prospects of Enactment

The Senate voted 30-8 to send the bill to the Assembly after it quickly passed the Senate Energy, Utilities and Communications Committee and the Senate Appropriations Committee. The Assembly could vote on the bill next week.

Newsom originally proposed a windfall profits tax on oil companies. (see Newsom Opens Special Session with Proposed Oil Profits Penalty.) Legislation to implement that proposal would have constituted the imposition of a new tax and required a two-thirds majority to pass. The revised bill to impose a penalty structure requires only a simple majority for passage.

Governor Gavin Newsom introduced an amended proposal to his oil profits penalty that would give the state regulatory increased oversight authority. The amended proposal marks the abandonment of his proposed legislation to penalize “excessive” oil company profits in response to record high gasoline prices in California. (see Newsom Opens Special Session with Proposed Oil Profits Penalty.)

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The March 15, 2023, amended proposal would provide the California Energy Commission (CEC) with increased funding for a new oversight department with subpoena authority to monitor gasoline prices and investigate price spikes.

The CEC would be authorized to begin a rule-making process to impose on a penalty or other regulations to address high gasoline prices. It would not require the regulator to cap profits or penalize the industry. The new proposal would also require oil companies to provide more data to state regulators.

“What we’re asking for is simple: transparency and accountability to drive the oil industry out of the shadows,” Newsom said in a statement. “Now it’s time to choose whether to stand with California families or with Big Oil in our fight to make them play by the rules.”

The revisions come a few weeks after Newsom’s earlier proposal floundered. The legislature held one hearing in which lawmakers expressed concern of unintended consequences to gasoline prices given the complicated nature of the oil markets. Uncertainty about the right strategy prevented any action.

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“After evaluating the company’s exemption request, the NRC staff determined that the exemption is authorized by law, will not present undue risk to the public health and safety, and is consistent with the common defense and security,” the Commission’s statement said.

The Diablo Canyon nuclear power plant, near Avila Beach in San Luis Obispo County, is the largest power source in California and provides 8.6% of the state’s electricity, including approximately 17% of its zero-emissions electricity. The current operating licenses for the plant’s two units expire in 2024 and 2025. Concerns over anticipated power shortages during the state’s transition to renewable energy led to growing support for keeping it open. (See California Keeps Diablo Canyon Nuclear Power Plant Open); (see CEC Approves Analysis Recommending Extending Life Diablo Canyon Power Plant).

CEC Approves Analysis Recommending Extending Life Diablo Canyon Power Plant

Earlier in the week, on February 28, 2023, the California Energy Commission (CEC) today approved a staff analysis recommending the state extend operation of the Diablo Canyon Power Plant through 2030. The determination found that Diablo Canyon is necessary to ensuring electricity reliability and was based on data showing California risks energy supply shortfalls during extreme weather events driven by climate change.

In September 2022, Governor Gavin Newsom signed into law S.B. 846, which extended the life of the 2,250 MW Diablo Canyon nuclear power plant’s two units by five years to 2029 and 2030. The bill required the CEC to determine the need to extend the plant’s license to operate beyond its 2025 expiration date.

The CEC will publish additional analysis this year comparing the cost of alternatives to the cost of extending the Diablo Canyon Power Plant. The California Public Utilities Commission (CPUC) is also evaluating how the extension could impact electricity rates.

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S.B. 1137 implements a 3,200-foot buffer zone, known as a setback, between oil wells and schools, homes, daycares, parks, playgrounds, healthcare facilities, community resource centers, detention facilities, and businesses open to the public. The law also requires existing wells in these areas to meet additional health, safety, and environmental requirements by January 1, 2025.

The California Independent Petroleum Association (CIPA) spearheaded the signature gathering campaign. Opponents of the law argued that it endangers California jobs and threatens to further increase California’s gasoline prices by decreasing in-state energy supplies. (See Referendum on Oil Drilling Setback Likely to Make 2024 Ballot.)

In response to the qualification of the ballot initiative, Governor Gavin Newsom said: “It’s one thing for Big Oil to make record profits as they rip off Californians at the pump. It’s quite another to push to continue harmful drilling near daycares and schools and our homes. Greedy oil companies know that drilling results in more kids getting asthma, more children born with birth defects, and more communities exposed to toxic, dangerous chemicals – but they would rather put our health at risk than sacrifice a single cent of their billions in profits.”

“I proudly signed SB 1137 last year to stop new oil drilling in our neighborhoods and protect California families,” Newsom said. “Big Oil knows that California is moving beyond fossil fuels, so on their way out these corporations are doing everything they can to squeeze out profits as they pollute our communities. We’re not standing for it. California will hold Big Oil accountable, and it starts with passing our price gouging penalty to prevent extreme gas price spikes like the one we saw last fall.”

The Los Angeles Times, in an editorial, argued that “there is really nothing preventing California’s state oil and gas regulators from acting to prevent neighborhood drilling in the interim, by denying oil companies permits for new wells in these buffer zones.” It argued that Newsom should direct CalGEM “to use its administrative authority to adopt rules to prohibit new drilling in those areas.”

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The new plan reduces by 75% how much credit solar customers receive when exporting their excess power to the grid. It also changes the electricity rate structure to encourage people to store their solar energy during the day and export it or use it in the evening. Critics say the proposal could slow rooftop solar installations.

The NEM subsidy was implemented in 1997 and has helped rooftop solar growth in recent years. Utilities, however, argue that the amount solar customers pay does not cover their share of grid maintenance costs and this increases costs for non-solar customers. In December 2021, CPUC released a proposal that would have required monthly grid connection fees for new solar customers. The plan was rejected of public backlash. The new plan does not include the grid connection charges.

Proposal

The proposal provides extra credits to residential customer bills who adopt solar over the next five years. The proposed:

• Rate structure: Applies new residential rates to incentivize electricity use when it is most beneficial for grid reliability. These rates have significant differences between peak and off-peak prices to incent battery storage and load shifting from evening hours to overnight or midday hours. The rates promote technologies such as battery storage, electric vehicles, and heat pump water heaters, which are important for achieving carbon neutrality.

• Solar tariff: Credits solar and solar plus battery storage customers for the electricity they export to the grid based on its value, as determined by the avoided cost to their utility of buying clean electricity elsewhere. This will incentivize solar exports during the late afternoon and early evening hours, particularly in the summer, when the grid is the most stressed.

• Solar credits: Provides extra electricity bill credits to residential customers who adopt solar or solar paired with battery storage in the next five years, which are paid on top of the avoided cost bill credits. Customers lock in these extra bill credits for nine years.

• Additional low-income credits: Provides low-income customers more access to solar by providing a larger amount of extra bill credits to ensure the solar system payback is just as attractive as the payback for higher-income customers (nine years or less).

• Greater solar coverage: Allows solar systems to cover 150 percent of a customer’s electricity usage to accommodate future electrification of appliances and vehicles.

A.B. 327 (2013) requires the CPUC to reform the NEM program, as well as conduct rate reform and distribution planning activities.

In his November 30, 2022 proclamation on the special session, Newsom stated that the purpose of the session was to consider legislation for new “financial penalty on excessive margins” along with increased oversight of industry “costs, profits, and pricing in the refining, distribution, and retail segments” of the California gasoline market. The opening of the special session followed the California Energy Commission’s (CEC) November 30, 2022 hearing on record gas price.

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In September, Newsom called for a windfall tax on oil companies “that would go directly back to California taxpayers.” He later called for the December special legislative session “to address the greed of oil companies.” Newsom stated at the time that “[g]as prices are too high. Time to enact a windfall profits tax directly on oil companies that are ripping you off at the pump.” (see Newsom Calls Special Legislative Session to Consider Tax on Oil Companies.)

The legislative leaders convened the December 5 session only long enough to adopt rules and appoint leaders. The legislation will be considered in earnest in January, when the session reconvenes. The special session will run concurrently with the regular session and could last as long. Special sessions are designed to expedite the passage of new legislation, as bill considering during special sessions are exempt from the requirement for regular session bills that a bill cannot be acted upon until 30 days after its introduction. A law passed during a special session also goes into effect 90 days after the session adjournment. Regular session bills generally go into effect on January 1 of the following year.

Proposed Legislation

The proposed legislation would impose a maximum annual profit margin for oil refiners and penalties depending on how much a company exceeds the profit margin maximum. The margins would be adjusted annually. Revenue collected from the penalty would be collected in the Price Gouging Penalty Fund and returned to taxpayers through rebates or refunds. The proposal does not state the specific profit margins or specific fines on amounts that exceed the margin. “Either Big Oil reins in the profits and prices, or they’ll pay a penalty,” Newsom said.

The proposal refers to the fine as an “administrative civil penalty” rather than a tax, requiring only a simple majority for passage rather than the two-thirds majority needed to pass tax legislation. This change in definition could prove critical in passing any legislation, as lawmakers might be reluctant to impose such a tax without overwhelming evidence of oil company price gouging.

Additional details on the proposal follow:

Excess Profits Penalty

The bill would ament the Public Resources Code to implement a “maximum gross gasoline refining margin,” which is defined as the maximum amount of gross gasoline refining margin excluding “state program costs” as defined in the bill. The CEC would be able to adjust the maximum gross gasoline refining margin “based on market data as necessary to fulfill the intent and purposes of the section and to ensure that a full and affordable supply of gasoline is available to Californians.” The CEC must notify refiners of the new maximum gross gasoline refining margin within 15 days of an adjustment, and adjustments are effective on the first day of the calendar month at least 15 days after the CEC provides notice of the adjustment.

The CEC may petition a court to enjoin a refiner from violating the maximum gross gasoline refining margin and may impose an administrative civil penalty for a violation. The amount of the penalty would be based on the amount by which the refiner’s gross gasoline refining margin, excluding state program costs, exceeds the maximum gross gasoline refining margin. The amount would be converted from barrels to gallons and multiplied by the number of gallons sold by the refiner during the calendar month through all transactions.

Before imposing the penalty, the CEC executive director would be required to serve a complaint on the refiner, hold a hearing, adopt a decision, and require payment of the penalty. Penalties collected are to be deposited into a Price Gouging Penalty Fund and returned as refunds to residents. The CEC would assess the penalties on a quarterly basis.

The CEC would also have the discretion to grant a refiner’s request for an exemption from the maximum gross gasoline refining margin upon the refiner showing reasonable cause. The refiner would be subject to alternative maximum margins or other conditions as the commission may set.

Increased CEC Oversight

The bill states that it is the intent of the legislature to enact legislation that would increase CEC oversight of refineries by requiring the commission to conduct regular assessments of the supply and price of transportation fuels in the state and of the impacts of refinery maintenance and turnarounds on fuel supply and prices.

The legislature would also expand the CEC’s authority to investigate and obtain necessary information from market participants, including information on pricing, supply contracts, and inventory management. It would also expand the CEC’s authority to order the rescheduling of refinery maintenance and turnarounds to avoid supply shocks in the transportation fuel market.

The legislature would also require the CEC and the California Air Resources Board to plan for and monitor progress toward the state’s “reliable, safe, equitable, and affordable” transition away from petroleum fuels. The agencies would do this in consultation with the refining industry and issue periodic reports to the governor and to the legislature. Lastly, the legislature would supplement existing refinery reporting requirements with legislation requiring more detailed reports to the CEC on transportation fuel imports, inventory levels, and transactions, and on refinery maintenance and turnarounds.

Gasoline Price Investigation

The bill also states the intent of the legislature to enact legislation to direct the California Department of Tax and Fee Administration and the CEC to investigate and report on the drivers of and factors affecting the price of gasoline in the refining, distribution, and retail segments of the gasoline market. The aim of the report would be to uncover pricing irregularities in the California gasoline market and their effect on state tax revenue.

BOEM will offer five California OCS lease areas that total approximately 373,268 acres with the potential to produce over 4.5 GW of offshore wind energy. The California Final Sale Notice (FSN) includes three lease areas off central California and two lease areas off northern California.

The announcement comes less than two weeks after BOEM released its final Environmental Assessment and Finding of No Significant Impact (FONSI) to the environment for the Morro Bay WEA. (see BOEM Completes Environmental Review of Morrow Bay Offshore Wind Area.)

The Biden administration has set a national target of 30 GW of offshore wind by 2030. (see Offshore Wind Makes Initial Advancements in California.) The Biden administration also announced a multi-department effort to support the deployment of 15 GW of power by 2035 through new floating offshore wind platforms. (see Biden Administration to Support 15 GW of Floating Offshore Wind.) California’s steep continental shelf and increased wind speeds make floating turbines the primary technically feasible option along the west coast.

In May 2022, the Department of the Interior issued a proposed offshore wind lease sale off the California coast, three years after BOEM identified three possible offshore wind energy areas on the Outer Continental Shelf off the California coast: Humboldt, Morro Bay, and Diablo Canyon.

The statement follows Newsom’s call in September for a windfall tax on oil companies “that would go directly back to California taxpayers.” In calling for the December special session, Newsom said his administration needs time to review similar taxes in the European Union.

Gasoline prices in California are $2.50 a gallon higher than the national average. California gas prices hit at an average of $6.42 a gallon on October 5, 2022, nearly reaching the record average of $6.44 a gallon set in June 14.

Supplies of gasoline in California are limited, as it least five refineries are down for maintenance. In response, on September 30, 2022, the governor directed the California Air Resources Board (CARB) to allow the early distribution of the higher polluting winter blend and called for a windfall profits tax on oil companies. (see Newsom Directs CARB to Allow Early Release of Winter-Blend Gasoline.)

Newsom said refinery maintenance was not the cause of the surge in price, as such maintenance occurs each year. He has argued that California’s environmental regulations are not the cause of the high prices, as the regulations do not equal the roughly $2.50 per gallon more.

“This is just rank price gouging. They can get away with it,” he said during a news conference. “They’re taking advantage of you, every single one of you, every single day. Hundreds of millions of dollars a week they’re putting in their pockets, lining their pockets at your expense, and then polluting this planet and leaving us all the external realities and costs associated with that.”

Others argue that the issue is not as simple. California requires a special blend of gasoline to reduce smog-producing emissions. The state also has higher taxes than other states and a higher cost of doing business. Refiners are also discouraged from investing in production improvements, as the state has mandated a move to zero-emissions vehicles. (See All New Cars Sold in California Must be ZEVs by 2035.)

Earlier efforts at windfall profits taxes, including a tax imposed in the United States during the 1980s, have failed to raise the expected revenue. The issue of determining whether profits in a volatile energy market are a “windfall” also contributes to the difficulty in imposing such a tax. There is also the risk that imposing the tax could discourage the investment needed to reduce prices.

In a radical change to U.S. energy tax policy, the Act does not set an expiration date for most tax credits but instead links the duration of the credits to the overall U.S. reduction in GHG emissions, of which carbon is the primary emission. Several estimates find that the IRA could help the United States reduce economy-wide GHG emissions to 40% below 2005 levels by 2030, bringing the United States closer to President Biden’s target to reduce GHG emissions by 50-52 percent from 2005 levels by 2030.  Far from their historical role to support energy production as a way to address energy security concerns, tax credits are now being used to combat climate change by promoting a transition to a de-carbonized U.S. electricity sector. Given this sustained effort, and the absence of other federal climate programs, energy tax policy is now climate policy.

A Focus on Tax Policy

With this focus on energy tax credits, the United States has forgone other approaches to reduce GHG emissions in the electricity sector, notably a federal cap-and-trade program, a federal renewable portfolio standard (RPS), and a federal feed-in tariff.  A federal cap-and-trade program was last seriously considered in the American Clean Energy and Security Act of 2009, which failed in the House of Representatives, and in the Clean Energy Jobs and American Power Act of 2010, which failed in the Senate. (The 2009 bill also included a proposed 3% federal renewable electricity standard, which is similar to an RPS). 

These policies have instead been pursued at the state and regional levels. California, the most active state in terms of climate policy, has enacted a series of climate bills since 2002. This includes GHG emission standards for passenger vehicles under AB 1493 (2002) along with GHG emission reduction targets of 1990 levels by 2020 under AB 32 (2006) and 40% below 1990 levels by 2030 under SB 32 (2016). AB 32 authorized the California Air Resources Board (CARB), the state’s clean air regulator, to develop a cap-and-trade program to reduce GHG emissions, and AB 398 (2017) extended the cap-and-trade program until 2030. Further, SB 100 (2018) set a goal for the state to reach 100% clean electricity by 2045.

In 2022, while the federal government put its focus on indirect tax credits, California continued to pursue more direct regulation and set new clean energy and emissions reduction targets. S.B. 1020 set interim targets that require that renewable and zero carbon sources make up 90% of the state’s electricity by 2035 and 95% by 2040. A.B. 1279 established a target of net-zero GHG emissions as soon as possible but no later than 2045 and net negative GHG emissions after 2045. The state also established a carbon removal and storage program under S.B. 905, targets for natural carbon removal and storage under A.B. 1757, and restrictions on oil drilling with a 3,200-foot buffer zone for oil wells under S.B. 1137. With implications for the state’s electrical grid, CARB also approved regulations to require the phase-out of the sale of new gasoline-fueled or diesel-fueled automobiles by 2035. (see California Implements More Ambitious Climate Agenda.)

Tax Credits and the Energy Transition

The Section 45 PTC and Section 48 ITC have been the primary tax incentive for renewable electricity, and the IRA has made them largely permanent. This is a significant change from past policy in which credits were implemented temporarily, with the expiration date regularly extended often after lapsing.  In implementing this change, the IRA renews and extends the Section 45 PTC and Section 48 ITC for existing renewable energy technologies through 2024. It then transitions to a new “technology-neutral” PTC under Section 45Y and ITC under Section 48E. These new “technology-neutral” tax credits provide continued support for established technologies and incentives for investment in new sources of zero-emissions energy production and energy transition technologies. The credits will remain in effect until the later of 2032 or a reduction in annual U.S. GHG emissions from electricity production equal to or less than 25 percent of GHG emissions for 2022.

To promote the development of clean energy technologies and domestic clean energy supply chains, the Act also adds a new IRC Section 45X advanced manufacturing PTC and expands the Section 48C advanced energy project ITC. It also makes stand-alone energy storage eligible for the Section 48 ITC, provides a new PTC for clean hydrogen, provides a new PTC to maintain production from existing nuclear facilities, and extends and expands Section 45Q carbon capture and sequestration tax credit. The Act also replaces the current energy tax credit system with a system of base credits and bonus credits to support domestic wages, domestic manufacturing, and investment in disadvantaged communities.

The IRA also implements transferable tax credits in an attempt to end project developers’ dependence on “tax equity” partnerships to finance projects. The value of tax credits is in offsetting a tax liability, and renewable energy projects usually require a number of years to generate taxable income.  Projects with minimal or no tax liability have often relied on investors to “monetize” tax credits.  In this type of transaction, investors with tax liability provide project capital in exchange for the tax credit that allows the investor to reduce its tax liability. The tax equity market has proven limited, however, with a small number of investors. Tax equity transactions also increase financing and transaction costs and reduce the amount of the credit that goes to the renewable energy developer. Scholars have recommended using direct cash subsidies or direct payments or making the tax credits refundable or tradable, and the IRA has implemented credit transferability with some limitations.

Taxes, and Spending?

Tax credits have long be a crucial component of a federal energy policy that relies on decentralized markets rather than on centralized regulations.  The use of credits as the primary GHG emissions strategy, however, is largely political. The most direct way to reduce carbon emissions is to price carbon through taxes or a cap-and-trade program. While this would encourage conservation and the use of renewable energy sources, it would also increase the cost of energy and risk political backlash.  Tax credits, by contrast, are a way to subsidize energy production from alternative energy sources and indirectly reduce carbon emissions.  Most significantly, it is easier to shield the public from their costs.

Tax credits are tax expenditures, which reduce federal revenue and, according to the U.S. Government Accountability Office (GAO), “have the same net effect on the federal budget as spending programs.” Politically, however, they are quite different. Tax expenditures can avoid annual review that is required for other spending measures, protecting them from increased political and public scrutiny and benefitting from political appeals to reduce taxes.  Tax expenditures also require only one legislative act and passage by only the Senate Finance Committee and the House Ways and Means Committee.   By contrast, direct spending requires authorizing legislation that is reviewed by subject-specific legislative committee, separate legislation to appropriate funds, and consideration by each chamber’s appropriations committee.  

Public support for a transition to renewable energy requires that energy remains affordable. It is politically easier to provide incentives, such as tax credits for renewable energy, rather than to impose direct costs through increased taxes.  In this sense, energy tax policy does not follow economic principles but rather is guided by political factors.

Energy and Political Transitions

In addition to its central role in energy policy, the energy tax credits in the IRA mark a significant transition in U.S. foreign and economic policy. For climate diplomacy, by helping the United States toward its Paris Accords commitment to reduce GHG emissions by 50% of 2005 levels by 2030, the Act will provide credibility that can allow the Biden administration to push for more ambitious climate targets during international climate negotiations.

The Act also has significant implications for U.S.-China relations. With the tax credits for domestic clean energy manufacturing, the United States has indicated that it will not use carbon pricing to compete with China, as the European Union is doing with its proposed carbon border tax. It will instead pursue a policy of support for onshoring domestic clean energy supply chains.

This strategy brings risks. Attempts to bring the renewable energy supply chain away from low-cost China to the United States could increase energy costs. The increased use of wind, solar, and batteries will greatly increase demand for metals and rare earth minerals, increasing the cost of minerals, materials, labor and other inputs. These trends could increase energy costs, accelerate global inflation, and make renewable energy uneconomic. Additionally, the U.S. strategy could have unintended, but easily foreseeable, consequences, as the IRA’s promotion of solar and wind energy could actually push the United States even more dependent on China for solar panels and wind turbines.

Using tax credits to increase deployment of renewable energy and decarbonize the economy will take years and probably decades. The U.S. energy system will also need significant investment in energy transmission lines to distribute electricity from renewable energy.  Given these challenges, an energy transition will likely be more gradual than expected.

During this transition period, the U.S. economy will remain vulnerable to oil supply shocks, geopolitical risks, and overall rising energy prices. This will subject the IRA’s energy tax policy to significant political risks. Rising energy prices could bring a backlash against renewable energy and lead to repeal of the bill. Coupled with increasing budget deficits, tax expenditures could be subject to greater political scrutiny. Failure to reduce emissions as projected could also bring a change in policy. Overall, the success of the IRA will depend on whether the benefits of the clean electricity outweigh the rising cost of energy.

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The exclusion of solar energy from a property value reassessment is seen as a valuable incentive for increasing the deployment of solar energy properties. Solar is viewed as critical to meeting the state’s clean energy goals. Newsom, however, noted the costs of the tax exclusion, stating that he urges the legislature to “consider the impacts to local agencies before bringing forward another extension of this policy.

Proposition 13 Exemption for Solar Energy

California property tax law classifies solar projects as real property. Under Proposition 13, the state constitution limits real property taxes to 1% of a property’s “full cash value” and limits annual property valuation increases to the lesser of inflation or 2% of its base year value. A reassessment of the property value is triggered when the property is “purchased, newly constructed, or a change in ownership has occurred.”

In 1980, California voters approved Proposition 7, which authorized the legislature to exclude the construction or addition of any active solar energy system from the definition of “newly constructed.” AB 1306 added Section 73 to the Revenue and Taxation Code to implement Proposition 7. The solar energy exclusion was modified and extended several times in the intervening decades. In 2014, SB 871 extended the exclusion through the 2023–24 fiscal year and extended the repeal date to January 1, 2025.

Active Solar Energy System

The law defines an “active solar energy system” as a system that is built as part of a new property, or the addition of a system to an existing property. The system must use solar line devices that are thermally isolated from living space or any other area where the energy is used to provide for the collection, storage, or distribution of solar energy. The system may be used for a domestic, recreational, or therapeutic uses, or for water heating, space conditioning, electricity production, process heat, or solar mechanical energy. The definition excludes swimming pool heaters or hot tub heaters.

Provisions on Local Reimbursements

The bill also excludes the extension from requirements that any bill extending an existing tax expenditure contain specified goals, purposes, and objectives that the tax expenditure will achieve, detailed performance indicators, and data collection requirements.

The bill provides that if the Commission on State Mandates determines that the bill contains costs mandated by the state, the state would be required to reimburse local agencies and school districts according to the required procedures. The bill also provides that no appropriation is made and the state shall not reimburse local agencies for property tax revenues lost by them pursuant to the bill.

Lithium and EVs

Lithium is a metal used to produce batteries in electric vehicles and computer electronics. Currently, the global supply of lithium comes from Argentina, Chile, China and Australia. California’s lithium deposits are seen as critical for both helping the U.S. become a global lithium producer and in developing an in-state supply chain for the state’s move to zero-emission vehicles (ZEVs). (For background, see All New Cars Sold in California Must be ZEVs by 2035 and see California Taxes Lithium, a Key Component in EV Batteries.)

CAEATFA has developed a list of Emerging Strategic Industries that includes activities associated with the development, exploration, and production of lithium within California’s “Lithium Valley.” These industries are identified as having a potentially significant impact on the state’s environmental goals or economy.

CAEATFA

The California Alternative Energy and Advanced Transportation Financing Authority (CAEATFA) was established in 1980 to finance renewable energy projects. Its authority was expanded in 1994 to fund “advanced transportation” projects. In 2008, CAEATFA implemented an existing sales tax exclusion for equipment used to manufacture advanced transportation products. The 2008 exclusion largely benefited Tesla Motors.

The legislature then authorized the sales tax exclusion program with the passage of S.B. 71 in 2010. The law expanded that exclusion to alternative energy manufacturers by authorizing a $100 million exclusion from sales tax for projects that “promote the creation of California-based manufacturing, California-based jobs, the reduction of greenhouse gases, or reductions in air and water pollution or energy consumption.” CAEATFA has awarded the full $100 million each year since 2015.

In December 2018, the Legislative Analyst’s Office (LAO) issued an evaluation of the CAEATFA tax exclusion program and recommended that the state allow it to expire. The LAO noted that the CAEATFA program and the partial sales tax exemption for manufacturing and research and development activities overlap. It concluded that the partial manufacturing exemption is broader than the CAEATFA program and easier for businesses to use.

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The Diablo Canyon nuclear power plant is the largest power source in California and provides 8.6% of the state’s electricity, including approximately 17% of its zero-emissions electricity. The plant’s two units were scheduled to be retired in 2024 and 2025, but concerns over anticipated power shortages during the state’s transition to renewable energy led to growing support for keeping it open. Newsom originally proposed a 10-year extension, but legislators rejected that proposal in favor of the shorter timeline. (See Newsom Introduces Bill to Keep Diablo Canyon Nuclear Power Plant Open here.)

The legislature stated that it is keeping the plant open to “protect the state against significant uncertainty in future demand resulting from the state’s greenhouse-gas-reduction efforts involving electrification of transportation and building energy end uses and regional climate-related weather phenomenon, and to address the risk that currently ordered procurement will be insufficient to meet this supply or that there may be delays in bringing the ordered resources online on schedule.” PG&E must now obtain licenses for the extension from the California state agencies and the U.S. Nuclear Regulatory Commission.

$1.4 Billion Forgivable Loan

The law provides a $1.4 billion forgivable loan for PG&E to extend operations of the Diablo Canyon power plant facility to November 1, 2029 for Unit 1 and November 1, 2030 for Unit 2. The law transfers $600 million from the General Fund to the Department of Water Resources and states that the transfers of the remaining $800 million requires future legislative authorization. In a change from Newsom’s original proposal, the amount is not to be paid in a lump sum but rather to be paid in semi-annual disbursements according to review procedures. Among other requirements for the loan, PG&E must conduct an updated seismic assessment on the plant.

Regulatory Streamlining

The legislation also streamlines and expedites the regulatory process for the extension. It would require state agencies to take action on an application or request for an extension within 180 days of submission.

Federal Funding

The law requires the Diablo Canyon plant to secure funds from the U.S. Department of Energy or other federal sources to pay back the loan. It requires the plant to qualify for the U.S. Department of Energy’s $6 billion Civil Nuclear Credit program by March 1, 2023, or the loan will be canceled. PG&E has applied for federal aid from the program, which was created in the 2021 Infrastructure Investment and Jobs Act to help nuclear power plants maintain operations. Diablo Canyon is the only plant expected to apply for the funding, as the 10-year nuclear power production tax credit passed as part of the Inflation Reduction Act could provide a better incentive.

Clean Energy Reliability Investment Plan

The bill also provides $1 billion from 2023 to 2026 under the Clean Energy Reliability Investment Plan to support “programs and projects that accelerate the deployment of clean energy resources, support demand response, assist ratepayers, and increase energy reliability.”

Most recently, in April 2021, the legislature considered SB 467, a bill that included the implementation of a 2,500-foot setback. The bill, which would have also prohibited new or renewed fracking permits, acid well stimulation, cyclic steaming, and water and steam flooding, failed to pass out of the Senate Committee on Natural Resources and Water.

S.B. 1137

The main requirements in S.B. 1137 are the health protection zones; the sensitive receptor inventory and map; indemnity bond for plugging and abandoning wells; the notice of attention to drill and offer to test the water; a leak detection and response plan; and emissions reporting. The bill exempts underground gas storage wells and the related production facilities from these requirements.

Health Protection Zones

Beginning January 1, 2023, the law establishes a “health protection zone” for new and reworked oil wells of 3,200 feet from a “sensitive receptor,” which it defines as a residence, an education resource, a community resource center, a health care facility, live-in housing, or building housing a business that is open to the public. The measurement must be made from the property line of the receptor. If the receptor building is set back more than 50 feet from the property line, the measurement is made from the outline of the building footprint to 3,200 feet in all directions.

There are limited exceptions to the requirement. This includes to prevent or respond to a threat to public health, safety, or the environment; to comply with a court order; or to plug and abandon or reabandon a well.

Sensitive Receptor Inventory and Map

The law also requires operators to submit a sensitive receptor inventory and map to the Geologic Energy Management Division in the Department of Conservation (CalGEM) by July 1, 2023. Operators must also provide updates to the inventory and map annually thereafter. CalGEM must make all current sensitive receptor inventories and maps publicly available on its website.

Indemnity Bond for Plugging and Abandoning

The law also requires the well operator to provide an indemnity bond sufficient to pay the full cost of plugging and abandoning the well and decommissioning any attendant production facilities. This requirement takes effect January 1, 2023.

Notice of Intention to Drill and Offer of Water Testing

At least 30 days before beginning drilling, the law requires operators to contact property owners and tenants within a 3,200-foot radius of the well and provide a record of delivery and offer to sample and test water wells or surface water on their property before and after drilling. If a property owner or tenant requests sampling and testing of a water well or surface water, drilling may not begin until a baseline water sample has been collected. The owner or tenant must submit the request in writing within 20 days from the date of the notice, and the surface property owner must make necessary accommodations to enable the collection of a water sample within 10 days from the date notice is provided. The operator must collect a follow up water sample 30-60 days after drilling is complete. The operating must pay for the water sampling and testing.

Leak Detection and Response Plan

The law requires all operators to submit a leak detection and response plan to CalGEM by January 1, 2025, with division approval or notices of deficiencies by January 1, 2026. The plan must be implemented by January 1, 2027. Beginning January 1, 2027, the operator shall suspend all production and injection operations within a health protection zone unless an approved leak detection and response plan is fully implemented in that area. CalGEM must hold public workshops related to the leak detection and response plans. Operators must also review and update their plans at least once every five years, and submit their plan for CalGEM approval.

Emissions Reporting

Beginning January 1, 2027, the law requires an operator with a well and an attendant production facility in a health protection zone to provide on annual report to CalGEM on its emissions system. This includes information on the number of and amounts of time the emissions detection system was not operating; the number of validated alarms, and the reasons for the alarms; the number of leaks that occurred, the time needed to repair the leak, and a brief description of the leak, including the impact on air quality and community exposure; the number of times the surrounding community was notified after a leak persisted for 48 hours; the number of times and length of time production and injection operations and other use of the facility were suspended due to leaks; any baseline and postdrilling groundwater testing performed by location; and the division shall make the information submitted by the operators available to the public on its internet website.

The Proposition 13 Exemption for Solar

California property tax law classifies solar projects as real property. Under Proposition 13, the state constitution limits real property taxes to 1% of a property’s “full cash value” and limits annual property valuation increases to the lesser of inflation or 2% of its base year value. New construction or a change in property ownership, however, triggers a property value reassessment.

Section 73 of the California Revenue and Taxation Code excludes the construction or addition of any “active solar energy system” from the definition of “newly constructed” through the 2023-24 fiscal year. An active solar energy system that qualifies for the exclusion before January 1, 2025 will continue to receive the exclusion until there is a subsequent change in ownership. S.B. 1340 would extend the exclusion through the 2025–26 fiscal year.

Solar Energy System

The law defines an “active solar energy system” as a system that is built as part of a new property, or the addition of a system to an existing property. The system must use solar line devices that are thermally isolated from living space or any other area where the energy is used to provide for the collection, storage, or distribution of solar energy. The system may be used for a domestic, recreational, or therapeutic uses, or for water heating, space conditioning, electricity production, process heat, or solar mechanical energy. The definition excludes swimming pool heaters or hot tub heaters.

Provisions on Local Reimbursements

The bill would also exclude the extension from requirements that any bill extending an existing tax expenditure contain specified goals, purposes, and objectives that the tax expenditure will achieve, detailed performance indicators, and data collection requirements.

The bill would also provide that if the Commission on State Mandates determines that the bill contains costs mandated by the state, the state would be required to reimburse local agencies and school districts according to the required procedures.

The bill would also provide that no appropriation is made and the state shall not reimburse local agencies for property tax revenues lost by them pursuant to the bill.

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Extension as Part of Climate Plan

The proposed legislation states that the “impacts of climate change are occurring sooner and with greater intensity and frequency than anticipated, causing unprecedented stress on California’s energy system.” Citing “supply chain disruptions, the impact of tariff disputes, and other delays in installation of new clean energy generation and storage systems,” the legislation notes a “substantial risk” that there will not be a sufficient supply of zero-emissions energy by the time of the scheduled plant closure.

The legislation also places the extension within California’s greenhouse gas emissions reduction plan. It states that if the powerplant operations are not extended, “increased energy production from greenhouse-gas-emitting sources will result, exacerbating the climate impacts already stressing California’s energy system…”

The legislation argues that “[c]ontinued operations of the Diablo Canyon powerplant for an additional five to ten years beyond 2024-25 is therefore critical to ensure statewide energy system reliability and to minimize the emissions of greenhouse gasses while additional renewable energy resources come online, until those new renewable energy resources are adequate to meet demand.”

Regulatory Streamlining

In addition to the forgivable loan to PG&E, the legislation would also streamline and expedite the regulatory process for the extension. It would require state agencies to take action on an application or request for an extension within 180 days of submission and would exempt the extension from the California Environmental Quality Act and coastal development permitting. The California Coastal Commission would also not be able to require new studies or collect additional data in connection with a certification of the plant’s under the federal Coastal Zone Management Act. Additionally, the bill would require the plant to pay a “mitigation fee” of $10 per million gallons of water for the impacts of ocean water intake at the plant.

Debate over Plant Closure

Diablo Canyon’s two units are scheduled to be retired in 2024 and 2025, but there is increasing support for keeping the plant open to avoid power shortages in the state. In addition to Newsom, California Senator Diane Feinstein recently reversed course to support extending the life of Diablo Canyon. She noted that closure of the plant could lead to “years of electricity shortfalls” and argued that the utility be relicensed and retirement delayed under the state can “replace its production with clean sources.”

The settlement ends a lawsuit that California filed in January 2020 challenging a Trump administration plan to open up 1.2 million acres of federal lands in Central California to oil and gas drilling, including fracking, without conducting an adequate environmental review. The lawsuit alleged that the Bureau’s environmental review of the project failed to evaluate fully the significant and adverse impacts on the communities and on the environment of Fresno, Kern, Kings, Madera, San Luis Obispo, Santa Barbara, Tulare, and Ventura Counties.

“Fracking is dangerous for our communities, damaging to our environment, and out of step with California's climate goals,” Bonta said in a statement. “The Trump Administration recklessly opened Central California up to new oil and gas drilling without considering how fracking can hurt communities by causing polluted groundwater, toxic air emissions, minor earthquakes, climate impacts, and more. In keeping with the Bureau of Land Management's mission to preserve the health of our public lands, it must reassess this Trump-Era mistake.”

The settlement is the latest development in a dispute that began in 2014 with the Obama administration’s plan to lease the land for oil development. The Bureau of Land Management agreed to environmental review in 2017, but the Trump administration moved forward with the 2014 plan without substantial changes.

The settlement also coincides with California’s efforts to ban oil drilling on state lands. In April 2021, Newsom issued an executive order that directed the Department of Conservation’s Geologic Energy Management Division (CalGEM), the state’s main oil regulator, to initiate regulatory action to end the issuance of new fracking permits by January 2024. Newsom also requested that the California Air Resources Board (CARB) analyze ways to phase out oil extraction across the state by no later than 2045 as part of the Climate Change Scoping Plan. In May 2021, CalGEM issued a draft regulation to ban all new fracking and other well stimulation permits starting in 2024.