The U.S. is still years away from establishing a national carbon tax or cap-and-trade system — and it’s certainly possible it will never take either step. But there are state and regional cap-and-trade programs in place to incentivize refiners and others to reduce their greenhouse gas (GHG) emissions. In today’s RBN blog, our fourth and final on carbon emissions and the refining sector, we look at state and international efforts to reduce GHG emissions and their prospective impact on the U.S. refining industry.

In Part 1 of this series, we gave an overview of emissions from refineries, technical ways to mitigate them, and how those policies might ultimately influence refining competitiveness. In Part 2, we investigated the policy options deployed in Europe and how its Emissions Trading System (ETS) is affecting the European Union’s (EU) refining industry as a whole, then looked at Canada’s carbon tax in Part 3, including how it works and the future impacts on oil sands producers, bitumen upgraders and refiners.

First, a reminder: A carbon tax and a cap-and-trade system are two distinct approaches to reducing GHG emissions. A carbon tax sets a fixed price on GHG emissions that is paid by all identified participants — typically fossil-fuel suppliers, power plant operators and other emission-intensive industries. Under a cap-and-trade system, in turn, the government sets a GHG emissions cap and then issues allowances, which permit a certain amount of emissions over a specific period. Covered entities can buy, sell, or trade those allowances to meet their emissions targets. This approach is designed to help ensure that the combined efforts of all participants are as cost-effective as possible.

To date, no state has implemented a carbon tax and neither has the federal government. There are two cap-and-trade programs currently employed in the U.S. — one regional and the other a single-state effort. The first to be developed was the Regional Greenhouse Gas Initiative (RGGI), which covers the Mid-Atlantic and Northeastern states but only applies to the emissions from fossil fuel power generators. The second system is the California Air Resources Board’s (CARB) cap-and-trade program, which covers about 80% of California’s emissions, especially large power and industrial emitters, including refineries.

Since the RGGI doesn’t impact refineries, we will focus on the CARB program, which as you would expect affects only refineries in that state. After that, we’ll look at a second way that a larger share of U.S. refineries and other industrial emitters may be impacted by carbon pricing, namely carbon border adjustment mechanisms (CBAM) in other countries.

California’s Cap-and-Trade Program

California’s Assembly Bill 32 (AB 32), enacted in 2006, directed CARB to establish a plan for the state to reduce its GHG emissions to 1990 levels by 2020, beginning in 2012. The cap-and-trade program established by the law is similar to the overall structure of the EU’s ETS, although there are some differences when you dig into the details. (We should also note that the CARB program is similar to the cap-and-trade system of Quebec, which we mentioned in Part 3.) AB 32 was also responsible for creating the state’s Low Carbon Fuel Standard (LCFS) program, which we’ve discussed in numerous blogs over the years.

Like the ETS or Canada’s output-based pricing system, benchmarks are set for 98% of the industrial emissions in California. Industrial emitters like refiners are allocated allowances according to a formula based on several factors, including annual facility output. In 2013 and 2014, the cap (blue line in Figure 1) was reduced by 2% annually; from 2015-20, the cap was reduced by 3% annually and is currently being reduced by 4% annually until 2030. The cap for refiners and other industrial emitters was set at 71.5% of their benchmarked emissions in 2024 (intersection of blue and red lines).

Only 17 of the 132 U.S. refineries that report their annual GHG emissions to the Environmental Protection Agency (EPA) are located in California — they accounted for 14% of U.S. refinery emissions in 2022. But there is a history of states following the stricter emissions standards set by CARB through a mechanism referred to as the California Waiver, which was created in 1967 under the Air Quality Act and revised in 1990 in amendments to the Clean Air Act. (According to the Congressional Research Service, 17 states and the District of Columbia have used the waiver to adopt some subset of California’s standards.) For example, Washington state enacted its cap-and-trade program in 2023 and is currently in the rule-making process to align its program with California and Quebec to allow for the wider trading of allowances. But this may not be a significant issue as many of the states more politically aligned with California do not have any refineries. More than one-half of U.S. refining emissions come from Texas and Louisiana, perhaps the two states least likely to adopt California’s approach anytime soon.

Carbon Border Adjustment Mechanism

As we noted above, a second path that might impact U.S. refiners and other industrial emitters is a CBAM. In Part 2, we discussed how the EU has implemented a CBAM structure requiring importers to pay for the emissions their goods produced during manufacturing. CBAMs usually give credit if the producer has already paid a price on carbon in the country of origin. U.S. refinery exports were not part of the initial phase of the EU’s CBAM, introduced in 2023, and are not expected to be included until 2030 at the earliest. While there are no plans to implement a carbon tax or cap-and-trade program in the U.S., some speculate that the adoption of CBAMs by other nations may ultimately prompt a change in Washington, DC. The thought is that if U.S. exporters are ultimately required to pay for their carbon emissions, that money might as well be collected in the U.S. under a carbon tax or traded with other U.S. companies under a cap-and-trade system.

While domestic and overseas drivers might result in an expanding or complete adoption of a mechanism for pricing carbon in the U.S., impacting refiners, we are probably still talking several years out to 2030 at the earliest. But how would increasing regulations that target emissions change the economics of U.S. refineries? Would more complex refineries with higher margins (and higher total emissions) see their advantage diminish, or would the impact be more evenly felt?

Figure 2 above charts the margins of the 25 largest U.S. refineries by crude throughput in 2023 and the increased costs associated with their carbon emissions under five possible carbon-cost scenarios ranging from $25 per metric ton (MT) to $400/MT. The refineries are ranked from the most profitable to least profitable, with the margins (dark blue bars) on top and the prospective associated costs (in $/MT) for the various potential carbon prices below (yellow, gray, blue, green and red bars). At the World Bank’s desired carbon cost of $100/MT (blue bars), refiners would pay an additional $3-$6/bbl for the oil they process, with expenses rising quickly at higher carbon costs (black and red bars).

These costs would ultimately pass through to the downstream supply chain and consumers (meaning pump prices for gasoline and diesel would increase considerably) and could change the competitive landscape for U.S. refiners. First, refiners would be able to improve their competitive position by reducing emissions. Second, the smaller, simpler refineries with the lowest margins are usually the price-setters in the market, making them more likely to idle operations or shut down when margins are weak. Third, if carbon prices were to go above $100/MT, some of the more complex and profitable refineries with higher emissions might be less competitive. (Of course, heavy-light differentials would likely also widen in response, at least partially offsetting that headline disadvantage.)

Most refiners outside of California probably won’t need to worry about the cost of carbon until at least 2030 but that doesn’t mean there are no incentives to reduce their GHG emissions. The Inflation Reduction Act (IRA), enacted in 2022, enhanced and expanded the federal 45Q tax credit for capturing and then utilizing or sequestering carbon dioxide (CO₂) emissions, which we detailed in Way Down in the Hole. One thing to note is that 45Q has always differentiated between utilization and sequestration of carbon, giving a higher credit to sequestration. (Current rates are $85/MT for carbon capture and sequestration, or CCS, and $60/MT for carbon capture, use and sequestration, or CCUS). However, there is a movement with bipartisan support to bring the two to parity, the logic being that you ultimately want to incentivize utilization to create a self-sustaining market for capturing CO₂. With the incentive route, those who do not wish to address their CO₂ emissions aren’t directly punished; however, they could become less competitive if the tax incentives are generous enough for those who choose to pursue them.

The downside to the U.S. adopting a carrot-but-no-stick approach to carbon reduction — subsidizing carbon capture (the carrot) without penalizing emissions (the stick) — is that there is no reward for figuring out how to emit less carbon within the production process. Once again, the 45Q tax credit offers no benefit to refiners focusing on efficiency gains or reducing hydrocarbons burned for heat. The tax credits also provide no incentive for eliminating methane emissions (more a producer/transporter problem than a refining one), a more potent GHG than CO₂. However, the IRA implements a methane fee (see Cover Me) to tackle that issue.

While a carbon price impacting the entire U.S. refining industry is probably quite far off, if it ever becomes a reality, there are two potential drivers — an adoption of CARB-like schemes by other states or the implementation of CBAM by other countries — that could one day lead to a federal cap-and-trade system or a carbon tax, and high-carbon-emitting refineries that do well financially today may not do as well if a carbon price materializes. While the U.S. has gone the tax-incentive route, such an approach will likely skew how refiners reduce their emissions by focusing on carbon capture over other potential approaches.

Note: The article was authored by Alex Hardman of Baker & O'Brien and published on RBN Energy's Daily Energy Post on December 11, 2024.

“Over the Hills and Far Away” was written by Jimmy Page and Robert Plant and appears as the third song on side one of Led Zeppelin’s fifth studio album, Houses of the Holy. Page and Plant wrote the song at Bron-Yr-Aur, a small cottage they rented in the Welsh countryside after finishing a massive North American tour with Led Zeppelin in 1970. The tune was originally called “Many, Many Times.” The intro section is played by Page on acoustic guitars, utilizing Eastern-influenced pull-offs in the key of G that Page is fond of. The midsection of the song is led by the band and guitar-driven riffs, followed by a quiet outro featuring Page on guitar and pedal steel guitar. The song was released as the first single from the album in May 1973 and went to #51 on the Billboard Hot 100 Singles chart. Personnel on the record were: Robert Plant (vocals), Jimmy Page (guitars, pedal steel), John Paul Jones (bass, piano, organ, Mellotron, synthesizer), and John Bonham (drums).

Houses of the Holy was recorded between December 1971-August 1972 with The Rolling Stones Mobile Studio at Headley Grange and Stargroves, and at Island and Olympic studios in London, with Jimmy Page producing and Eddie Kramer engineering. The album was released in March 1973 and went to #1 on the Billboard 200 Albums chart. It has been certified 11x Platinum by the Recording Industry Association of America. Two singles were released from the LP.

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