Proposals promise to deliver significant operational costs, market implications to the US refining industry.

The international treaty seeking to combat climate change—known as the Paris Agreement—was preceded by the Kyoto Protocol of 1997, which set target reductions of greenhouse-gas (GHG) emissions and of which a number of countries opted out or failed to meet the target schedules.

Unlike the Kyoto Protocol, nearly 200 countries signed the newer treaty. The 2015 climate deal limits the global temperature to just above pre-industrial times as a cornerstone and leads the way for a low-carbon future. Similar to the Kyoto Protocol, the Paris Agreement is based upon national or country voluntary emission cuts. Dissimilar to the Kyoto Protocol, the Paris Agreement has been endorsed by the U.S.

With no market incentive to reduce emissions and meet the agreement accords except for federal or state mandates or altruistic reasons, GHG emissions reductions will need a market or economic incentive to effectively meet the goals of the agreement. Policymakers are taking a serious look at carbon tax schemes as methods for providing the market drivers needed to achieve significant reductions while, counter intuitively, limiting economic burdens.

The landscape

Globally, a number of GHG regulations and policies address reducing carbon emissions. Current regulations include combinations of carbon taxes and emission trading schemes (ETS)—analogous to U.S. cap and trade. The EU has taken the lead on regulating carbon emissions, but there are new or emerging policies in the Far East, South America, Latin America and Canada.

In North America there are two regional programs— the Regional Greenhouse-Gas Initiative (RGGI) and Western Climate Initiative (WCI). The RGGI is a collaboration of U.S. northeastern states premised on a cap-and-trade program targeted for CO2 emissions from power plants. The WCI members include Quebec, Ontario, British Columbia in Canada, and California in the U.S. The WCI member’s programs are also based on cap-and-trade programs, except British Columbia, which is based on a carbon tax program.

Although there are no carbon tax programs in place in the U.S., a number of states are considering carbon tax initiatives as of press time. According to the Carbon Tax Center, these include Washington, Oregon, New York, Massachusetts, Rhode Island and Vermont. On a city level, Boulder, Colo., has implemented a carbon tax program on electricity generation.

Even with the U.S. House of Representatives resolution on condemnation of any tax on carbon, policymakers continue to look at carbon taxes as an instrument to effectively reduce CO2 emissions. In fact, the petroleum industry is “warming up” to a carbon tax scheme. ExxonMobil Corp. promotes a simple carbon tax to address GHG emissions as opposed to complicated regulations or programs, according to ExxonMobil’s Energy Factor.

A carbon tax primer

Policymakers have honed in on two primary instruments for regulating and pricing carbon, namely carbon tax and cap-and-trade programs. A carbon tax program prices a value on carbon emissions and lets the market determine the level of emissions reduction. Conversely, a cap-and-trade program limits carbon emissions and lets the market price the value of carbon emissions through allowances.

In a perfect world, both programs should arrive at the same point; however, this is not the case. Although the U.S. Acid Rain Program effectively reduced sulfur dioxide emissions through a cap-and-trade program, the U.S. Renewable Fuel Standard (RFS) program (another cap-and-trade program) is fraught with unattainable limits and market pricing manipulation, rendering the program effectively unworkable. Conversely, implementation and administration of a carbon tax program is more straightforward. It neither requires development of allowances nor management of problems associated with the RFS program. In addition, industry may prefer knowing the certainty of a carbon tax instead of the ambiguity of a cap-and-trade program.

To make a carbon tax more acceptable, policymakers are considering a number of program aspects to reduce overall impacts to the economy. A key aspect includes instituting a revenue-neutral scheme where the assessed taxes are returned back to consumers and/or industry. This aspect can be used to minimize the regressively “blunt” tax effect on less affluent and potential pull-down on the economy due to income effects.

Carbon tax prescriptions

According to the U.S. Environmental Protection Agency, CO2 represents roughly 80% of GHGs emitted in the U.S. Other emissions, like methane and hydrofluorocarbons (more potent GHGs), are more difficult to monitor and measure. Because of this, and for simplicity, policymakers are focusing solely on CO2 emissions.

In general, CO2 emissions and hydrocarbons that will emit CO2 will incur carbon taxes. Which sectors to include in a carbon tax program depend on emissions impact and ease of measuring. Primary sectors under consideration include electricity generation, industry, transportation and residential and commercial.

Click here to view Figure 1. 

For the petroleum refining industry, there are a number of points within the hydrocarbon supply chain to potentially apply a tax. Figure 1 illustrates an example of specific tax assessment points. As the tax points “move up” the supply chain, measuring and managing the program become more difficult. For instance, taxing crude oil would require allowances or rebates for portions of the crude oil that were not converted to CO2 emissions, like asphalts, lubes and petrochemical feedstocks. Therefore, it makes sense to tax at stack emission sources (because most of the data is already analyzed and available) and, for transportation fuels, apply an excise tax on the fuels distribution point based on the average fuels’ carbon concentration.

The amount of CO2 generated from combustion of a carbon-laden fossil fuel typically determines the carbon tax’s basis. A carbon tax price is generally referenced to a price per metric ton of CO2 emitted. Primary considerations for setting a carbon tax price include initial price as to not significantly disrupt the economy and price escalation as to eventually shift the economy from fossil fuels. The discussion of an initial range of prices has generally focused on between $15/mt CO2 and $45/mt CO2 .

Fossil fuel energy intensive industries will take the brunt of carbon tax costs. The petroleum refining industry, which includes the transportation sector, represents about 33% of CO2 emitted in the U.S. Electricity generation, which is on par with petroleum refining industry emissions, may have a material impact on refineries through power price increases.

Using the carbon tax scenario in Figure 1 as a basis, primary carbon tax impacts to the petroleum refinery industry are potential electricity price, in-plant emissions and transportation fuels price. Based on an arbitrary carbon tax rate of $30/mt CO2 , the annual financial cost due to the tax on the U.S. petroleum refining industry would be on the order of $500 million to $1 billion for electricity price increases, $4 billion to $6 billion for in-plant emissions and $60 billion to $80 billion for transportation fuels price increases. All inclusive, this tax rate reflects an impact of about $10/bbl of feed processed across the entire industry.

Refinery impact

The ultimate financial impact of a carbon tax to a refiner can be either direct or indirect. Direct costs are CO2 emissions from the combustion or transformation of fossil fuels in a refinery and are a function of a refinery configuration, crude slate and energy efficiencies. Indirect costs are supply increases and market dynamics and are a function of a refinery electricity source and refined fuels product price sensitivity…

This article first appeared in Downstream Business.