How might a Minnesota LCFS play out?

September 14, 2021 By , , ,

September 14, 2021
by Adam Schubert

In the U.S., several programs aim to reduce greenhouse gas (GHG) emissions per unit of energy of fuels used in transportation. California and Oregon both have low carbon fuel standard (LCFS) programs, one Canadian Province (British Columbia) also has a transport fuels GHG-reduction program, and Canada is in the process of rolling out its federal LCFS-style program. Washington state recently enacted its version of an LCFS program which will be implemented in 2023, and several other states (including New Mexico, Minnesota, and New York) are also considering programs to reduce emissions from transportation fuels on the basis of fuel energy.

Last month, we looked at how a New Mexico LCFS might play out. In this article, Stillwater examines the potential impacts of implementing an LCFS in Minnesota, including how such a standard would affect the supply, demand, and distribution of transportation fuels and how the standard would impact the cost and availability of such fuels.

Overview of Minnesota’s proposed legislation

This overview is based on HF 2083 as introduced during the 92nd session of the Minnesota House of Representatives (2021-2022). This bill was referred to the Committee on Commerce Finance and Policy where the LCFS proposal did not advance into the omnibus commerce bill in the special legislative session.[1] The proposed language of HF 2083 required the Commissioner of the Minnesota Department of Commerce (the Commissioner) to implement regulations implementing a Clean Fuels Standard (CFS) as outlined in the bill. For the purposes of this report, it is assumed that an LCFS similar to that proposed in HF 2083 is enacted by the Minnesota Legislature in its 2022 session, endorsed by the Governor, and enabling regulations are promulgated in a timely manner to allow program commencement on January 1, 2024.

Key provisions and omissions of proposed language included:

  • Mandating an LCFS structure which includes increasingly stringent annual CI-reduction targets with transportation fuels of above-target CI accruing deficits and transportation fuels of below-target CI earning credits. Deficit generators are required to annually acquire credits to offset their deficits.
  • Transportation fuels are very broadly defined to include electricity and liquid or gaseous fuels used to propel motor vehicles. Motor vehicles are defined to include trains, light rail, ships, aircraft, forklifts, and all road and nonroad vehicles.
  • The Commissioner is required to consult with the commissioners of transportation, agriculture, pollution control, and the public utility commission on applicable provisions of the CFS.
  • The regulations are required to be fuel neutral.
  • Policy objectives for the CFS include:
    • rural and urban development;
    • benefits to communities, consumers, clean fuel providers, technology providers and feedstock suppliers;
    • increased energy security from domestically produced fuels;
    • equitable transportation electrification based primarily on low-carbon and carbon-free electricity;
    • improving air quality and public health targeting communities disproportionately impacted by transportation pollution;
    • support state solid waste recycling goals through credits for RNG from organic waste;
    • support voluntary farmer-led efforts to adopt improved agricultural practices benefiting soil health and water quality while producing clean fuel feedstocks;
    • maximizes benefits to the environment and natural resources while protecting natural lands and biodiversity; and
    • is developed with broad outreach to stakeholders and communities bearing disproportionate health burdens from production, transport, and use of transportation fuels.
  • The standard is to achieve at least a 20% CI reduction from a 2018 baseline by 2035 by a stepwise annual schedule which steadily decreases CI each year. This schedule is to consider cost of compliance, available technologies, fuel quality requirements, and the list of policy objectives.
  • The 2018 baseline is based only on the relevant petroleum portion of fuels.[2]
  • Deficit generators are allowed to comply by either producing or importing low-CI transportation fuels or purchasing credits.
  • There must be a mechanism for credits to be traded and banked for future use subject to appropriate verification.
  • Pathway CIs are to be calculated by the GREET[3] model adapted to MN. The calculation must be consistent for all fuel types; science and engineering-based; and reflect differences in drive train efficiencies.

Key items not covered in the current version of the legislation include:

  • No defined implementation date is set. This will presumably be filled in before the bill advances to a vote.
  • No specified annual schedule of CI reductions. A minimum CI reduction of 20% by 2035 is stipulated along with steady annual reductions. The Commissioner appears to be granted authority to require larger CI decreases subject to general criteria specified in the act.
  • No cost containment mechanism. This includes no price cap or credit clearance market as currently included in the California and Oregon programs and specified for the recently enacted Washington program.
  • No specification that low-CI fuels be supplied for end-use in MN in order to generate credits.

Additionally, the scope of the current legislation appears to include aviation and marine fuels. The California and Oregon programs exclude deficit generation from these fuels due to limitations on the states’ authority under federal law.[4] The legality of MN’s inclusion of jet and marine fuels may need to be addressed before any legislation is submitted for a vote.

Transport fuels logistics – Current law

Logistics, supply, and demand of transport fuels in Minnesota

MN has no active oil or gas production; all crude processed by the two refineries located in the state is imported via pipeline. The two in-state refineries are the Flint Hills Pine Bend refinery and the Marathon St. Paul refinery, both located in the Minneapolis-St. Paul metropolitan area. The Flint Hills refinery is actually the largest U.S. refinery located in a state without any crude production. The Marathon refinery primarily supplies local demand through a terminal located adjacent to the refinery. The Flint Hills refinery supplies in-state demand as well as exporting refined products to Wisconsin and North Dakota via pipeline. Duluth and the far northern portion of the state have historically been supplied by the Husky refinery in Superior, Wisconsin.[5] The Marathon refinery in Mandan, ND supplies MN via the NuStar pipeline.  Minneapolis and the southeast portion of the state are also supplied via a BP pipeline from Whiting, IN. As of the third quarter of 2020, there were 2,068 retail gasoline stations operating in MN.[6] The locations of refineries, biofuel plants, terminals, and petroleum product pipelines in MN are presented in Figure 1 below.

MN is a major producer of ethanol and a significant producer of BD with twenty-two ethanol plants and four BD plants.[7] These facilities draw upon in-state production of corn, soybeans, and other feedstocks. Ethanol production capacity in 2020 was estimated at 1.354 billion gallons per year[8] and BD production capacity was estimated at 85 million gallons per year.[9] The state has long supported biofuels production and use in state with a mix of incentives and blending mandates for ethanol[10] (a minimum of 10% ethanol or other EPA-approved biofuels in substantially all gasoline sold in the state) and BD[11] (a minimum of 20% BD in all diesel fuel sold in state between the months of April[12] through September, with a 5% minimum during the rest of the year). The state has also been aggressive in providing support for gasoline retailers to offer E85 and E15 and annually reports on prices, availability, and sales volumes of E15, E85, and other gasoline-ethanol blends.[13] Even with this promotion of ethanol sales in-state, MN is estimated as being a net exporter of over 1 billion gallons per year of ethanol. The current BD requirement is estimated to make the state a net importer of over 34 million gallons per year of BD.

Figure 1. Minnesota Fuel Production and Distribution

Source: EIA State Energy Profile[14]

According to the EIA Prime Supplier Report data for 2019,[15] MN gasoline sales averaged about 150 thousand barrels per day (KBD), or 2.3 billion gallons per year; ultralow sulfur diesel (ULSD) sales averaged about 64 KBD (984 million gallons per year). MN mandates that substantially all gasoline contains a minimum of 10% ethanol.[16] The Minnesota Department of Commerce reports sales of E15, E20, E30, E40, E50, and E85.[17] Based on reported ethanol blending for 2019[18] and an assumption that E0 volumes are negligible, total fuel ethanol demand in the state in 2019 was 236.5 million gallons.[19] According to data published by the Minnesota Department of Commerce for April 2021[20], MN currently has 444 stations selling E85 and 401 stations selling one or more intermediate ethanol blends (E15, E20, E30, or E50). Diesel fuel sold in MN is mandated to contain a minimum of 20% BD between April 15th and September 30th, a minimum of 5% BD between October 1st and March 31st, and a minimum of 10% BD from April 1st to April 15th. Stillwater estimates that this corresponds to over 119 million gallons per year[21] compared to in-state BD production capacity of 85 million gallons.  EIA data on natural gas consumption as vehicle fuel in MN[22] indicates annual demand of approximately 507 million cubic feet (527 billion BTU, HHV or 4.7 million GGE),[23] or less than 0.1% of total natural gas demand of over 509,000 million cubic feet in 2019. The AFDC indicates that MN has 1,282 EV charging stations (1,176 public, 106 private). The Atlas EV Hub[24] indicates 12,878 EVs registered in MN as of February 2020 including 7,322 battery EVs and 5,556 plug-in hybrid EVs.

Value chain for transport fuels consumed and produced in the state

A schematic of the value chain for transport fuels consumed in MN is presented below in Figure 2. The market can be divided into liquid fuels (gasoline and diesel), electricity for EVs, and natural gas for NGVs. The large majority of gasoline vehicles are privately owned and primarily fueled at retail gasoline stations. Many diesel vehicles are owned by fleets with their own fueling facilities in addition to diesel fuel sold at retail. Electric vehicles are owned by both individuals and organizations (businesses, non-profits, and government agencies); charging of these vehicles is performed at private residences, private charging stations (primarily organization-owned), and at public charging facilities. NGVs are primarily owned by organizations and fueled at private compressor facilities with compressed natural gas (CNG) or liquefied natural gas (LNG); there is also some retail CNG fueling. The unique aspects of the value chains for liquid fuels, electricity, and natural gas are discussed in the following paragraphs.

Figure 2. Minnesota Transportation Fuel Value Chain

Liquid Fuels Value Chain

  • Refineries – The largest component of the liquid fuels value chain are the petroleum refineries. The in-state and out-of-state refineries supplying the Minnesota market are discussed above.
  • Pipelines – Gasoline and diesel fuel in MN is transported from refineries to distribution terminals via pipeline. The four major pipeline systems moving these products are:
    • Flint Hills – transports product from the Pine Bend refinery to terminals in around the state into North Dakota and Wisconsin.
    • Magellan Pipeline – supplies a network of terminals located around the state.
    • NuStar pipeline – transports fuels from the Mandan, ND refinery to terminals in western MN and the Minneapolis-St. Paul area.
    • Proprietary BP pipeline – transports fuels from BP’s Whiting, IN refinery to terminals in Spring Valley and Minneapolis-St Paul.

This mix of pipelines enables MN to benefit from a diversity of refinery supply, thus enabling market competition and supply reliability in the event of outages at any single refinery. The Magellan pipeline is a common carrier where products produced from different refineries are commingled. Renewable fuels, either neat or in blends with petroleum fuels, cannot typically be transported via pipeline.

  • Renewable Fuels (Ethanol, Biodiesel, Renewable Diesel) – As described above, MN is a major producer and exporter of ethanol and a significant producer of BD. Due to state mandates, substantially all gasoline marketed in MN is E10 (a blend of 10% ethanol in gasoline) with a significant and growing penetration of E15 and higher blends, State mandates also require a minimum of 5 to 20%[25] BD in all diesel fuel sold in the state. There is no current use of RD in the state as the California LCFS creates a large financial incentive for substantially all U.S. RD production and imports to be used there. As these fuels cannot be shipped by pipeline and production is local, the ethanol and BD used in MN is primarily transported by truck. Ethanol blending with gasoline predominantly occurs at terminals as does most BD blending; some BD blending is also performed downstream of terminals.
    • Ethanol Production – Fuel-grade ethanol in the U.S. is primarily produced from corn or grain sorghum (milo). Production facilities are generally located where they can source their feedstock within a radius of about 50 miles from the plant. As a result, nearly all plants are located in the corn belt. As one of the top ethanol producing states in the U.S., with 19 plants and a collective 1.354 million gallons per year of capacity,[26] MN is a large net exporter of ethanol to other states and internationally. Ethanol being transported more than one day’s round-trip by truck (300 to 500 miles) is transported by rail, mostly in unit trains.
    • Biodiesel Production – BD in the U.S. is primarily produced from vegetable oils (soybean oil and non-food grade corn oil produced at corn ethanol plants) with additional production from animal fats (tallow) and used cooking oil (UCO). Most production sites are located near feedstock sources. The diversity of feedstock types has resulted in plants being located across a larger portion of the U.S. than is the case for ethanol. As BD production volumes are typically smaller than ethanol production volumes, truck transport is common with terminals located long distances from production plants supplied by rail. MN produces most of its required BD at plants located within the state. Additional supplies are received by truck or rail from neighboring states.
    • Renewable Diesel Production – RD is generally produced from the same feedstocks employed for production of BD, although RD plants generally have more flexibility to handle lower quality feedstocks such as UCO. The largest RD producers in the U.S. (Diamond Green and the Renewable Energy Group, REG) are located on the Gulf Coast and ship substantially all of their product to California by rail or marine vessel. There are some smaller plants located in other parts of the country with a number of additional plants currently under development. The RD plant located nearest to MN is the Marathon plant in Dickinson, ND. For the foreseeable future, it is expected that substantially all domestic production will be sold in California, driven by the value of the LCFS program credits. The U.S. also regularly imports RD from Neste’s plant in Singapore with substantially all imports arriving by marine vessel in California. As RD is nearly identical to petroleum diesel, it can be sold directly to end users as well as blended with petroleum diesel. RD is stored at petroleum distribution terminals and either blended with petroleum diesel at the terminal or sold neat to retailers and end-user fleets.
  • Terminals – Terminals provide bulk storage of petroleum fuels (gasoline and diesel) and biofuels (ethanol, BD and RD). Petroleum fuels are received via pipeline, and biofuels are received via truck or railcar. Products from different producers are generally commingled in common tanks and, thus, must all meet a common set of specifications. Petroleum fuels and renewable fuels are blended at the time when they are loaded onto tank trucks for delivery to retail gas stations or end-user fueling facilities. Importantly, petroleum gasoline produced at refineries and stored at terminals is a sub-octane grade which must be blended with ethanol to meet the octane requirements for retail gasoline. MN has 15 terminals located around the state in order to minimize the distance that fuels need to be trucked to retail stations or end-user fueling facilities. When terminals have outages (due to supply or maintenance issues) marketers need to draw supply from alternative terminals, potentially incurring increased transportation costs due to longer distances.
  • Retail/Private Fueling – Most vehicle fueling occurs at retail gasoline stations; a number of vehicle fleets operating out of a central base location have dedicated fueling facilities. All these facilities, retail and private, receive their fuel via tanker truck from one or more local terminals. The 2068 active public gasoline stations in MN are scattered across the state with the highest concentrations in more highly populated areas or along major highways. Regardless of site branding, very few gasoline stations are owned by refiners. Those sites posting a refiner’s brand are generally independently owned and operating with franchise agreements with the refiner which requires them to exclusively market fuel supplied by the refiner. Many sites, particularly smaller sites in rural markets, are individually owned while others may be owned by a wholesaler (“jobber”) who owns a number of sites and leases them to operators. A growing share of stations are owned and operated by regional or national chains (such as Holiday and Casey’s). Additionally, a number of large-volume sites located in the parking lots of large format retailers (such as Wal-Mart, Costco, and grocery store chains) are owned and operated by the host retailer. These different ownership models influence marketing and pricing strategies as well as access to capital to invest in the equipment necessary to offer additional fuel products. Monthly fuel volumes at individual retail sites can range from 30,000 gallons/month at small sites in rural markets to over one million gallons per month at large-format stations in high-traffic areas.

Electricity (EV) Fuels Value Chain

While EVs currently consume only a small fraction of electricity used in MN, their charging needs create some unique requirements for the power grid.

  • Generation – According to EIA data for 2019,[27] approximately 75% of MN’s power generation (44.8 million megawatt-hours, MWh) was provided by utility companies and 25% (11.6 million MWh) by independent power producers (IPP) and combined heat and power plants (CHP, typically owned by industrial users). IPPs sell power to local and distant utilities on both a contract and a spot basis in order to meet varying demand by time of day, day of the week, and season of the year. The total supply generated in MN was less than in-state retail power demand of 67.0 million MWh. Of total in-state generation, 30% came from coal, almost 24% came from nuclear, over 21% came from natural gas, 2% came from solar, and 18.5% from wind. About 61% of retail power sales were from investor-owned utilities, 14.4% from publicly owned utilities, 0.11% by the federal government, and 26.4% from cooperatives. Carbon dioxide emissions from power generation were estimated at 937 pounds per MWh (425 gCO2/kWh). The distribution of power plants and high voltage transmission lines is shown in Figure 3 below.[28] It may be noted that there are two nuclear plants in the state, one located northwest of Minneapolis and the other southeast of Minneapolis; coal-fired generation is concentrated in the northern portion of the state; natural-gas-fired generation is primarily in the more populous southern and eastern portion of the state; wind generation is primarily in the western and southern portions of the state; and solar generation is broadly scattered in the southern portion of the state. Additionally, there are a large number of petroleum, biomass, and hydropower installations. MN implemented a Renewable Portfolio Standard (RPS)[29] with the adoption of Minnesota Statute 216B.1691 in 2007. It requires that Xcel Energy[30] supply its retail sales in the state with 31.5% renewables by 2020, other Investor-Owned Utilities (IOUs) supply 26.5% of their retail power sales in state from renewable generation by 2025, and that all other utilities supply 25% renewables by 2025. Additional requirements for Xcel Energy include a minimum 25% of retail sales in 2020 come from wind and solar (of which a maximum of 1% from solar) and that other IOUs are required to supply a minimum of 1.5% from solar by 2020, 10% of which must be met with systems of 20kW or less. Further, there is a statewide goal of 10% solar by 2030.[31]

Figure 3. Minnesota Power Generation and Transmission

Source: U.S. Energy Information Administration (EIA)

  • Transmission – The movement of power from the point of generation to large concentrations of demand is generally achieved through high-voltage transmission lines. These lines are particularly key for solar and wind generation which are often located in more remote areas where large tracts of low-cost land are available. As illustrated in Figure 3, MN has a fairly extensive network of transmission lines to enable connection of solar and wind generation to the power grid.
  • Substations – Power substations, typically located near clusters of users, step the power down from the high voltages used for long-distance transmission to the lower voltages required by local end-users. Substations are primarily owned and operated by electric utilities. Growth in power demand in an area or changes in the voltages required generally requires the construction of new substations or the upgrade of existing substations. The mechanisms by which utilities can recover the costs of these additions and upgrades are determined by the state utility regulator, the Minnesota Public Utilities Commission.[32]
  • Charging – The charging of EVs, particularly light-duty EVs, is generally divided into residential and non-residential categories. Most current EV owners have garages or other suitable off-street parking locations where they can install a personal charger. These residential chargers can be ordinary wall outlets (“Level 1,” using standard 120V service) or dedicated 240V units (“Level 2,” offering faster charging). Due to the required time to fully charge most EVs, Level 1 and Level 2 charging is most practical for locations where vehicles can be left to charge overnight. For EV drivers who cannot install a home-based charger (no garage or who live in multi-family housing) and EV drivers who need to recharge away from home, non-residential chargers are required. To reduce recharge times to a duration compatible with activities such as shopping or dining, high-speed chargers (generally high amperage DC charging) is required. These high-speed units are significantly more expensive than Level 1 or Level 2 chargers and generally require upgrades in local substations or local distribution lines, particularly if multiple chargers are to be sited in a common location. The cost of these required electric infrastructure upgrades can be difficult to pass along for charger units with low utilization. Public chargers can be installed and maintained by utility companies (often in a non-regulated entity), municipal governments, or private firms. State regulations concerning the resale of electricity through a charger can significantly impact the business model or the charging fees for public chargers. Another model for private charging is chargers located at workplaces for either company-owned vehicles or employee vehicles. Chargers to support heavy-duty EVs create additional challenges as those vehicles have larger battery packs and are generally operated by fleets which require multiple chargers at a given site to enable all of their vehicles to be charged during times when they are idle; this creates additional requirements for upgrades of local electrical infrastructure.

Natural Gas Vehicle (NGV) Fuels Value Chain

According to EIA data for 2019, less than 0.1% of natural gas consumption in MN was used for transportation fuel.[33] Nearly all that consumption is in the heavy-duty sector, primarily in centrally fueled fleets.

  • Production – Natural gas utilized in MN is nearly all fossil derived. MN has no in-state fossil natural gas production; all fossil natural gas used in state is delivered via pipelines from adjoining states and Canada. Argonne National Labs reports that the U.S. has 157 operational RNG facilities with 76 additional facilities under construction and 79 in development as of 2020.[34] None of the currently operational or planned sites are in MN. There is opportunity, however, to develop in-state RNG facilities at dairy and livestock operations, landfills, and waste treatment sites if the economics became feasible.
  • Processing – In order to recover natural gas liquids, such as ethane, propane, and butane from the raw natural gas and assure the consistent quality product required by natural gas users, the raw natural gas produced in the field is gathered and processed at gas processing plants located near the production sites before injection into common-carrier gas pipelines. As MN has no fossil natural gas production, there are also no gas processing plants located in the state. The natural gas is processed to pipeline specifications outside MN. Any RNG produced in MN would need to be upgraded to the pipeline specifications before injection into the pipeline system. That upgrading may be done by each producer or a facility treating gas produced by multiple producers within a given area.
  • Pipelines – Processed natural gas is injected into high-pressure pipelines for transmission to demand markets. These long-haul pipelines are typically operated as common carriers, transporting gas marketed by multiple firms and charging shippers tariffs which are regulated by the Federal Energy Regulatory Commission (FERC) for interstate pipelines or the state utility regulator for intrastate pipelines. The pipelines are generally owned by midstream companies which are often organized as master limited partnerships (MLPs) for tax purposes. Pipelines deliver gas to local utility companies who manage supply, delivery, and billing to end-users. Utilities typically operate a mix of high-pressure pipelines to service large volume users, such as power plants, and low-pressure pipelines to service the majority of its customers.
  • Compression – Because of its low energy density, natural gas needs to be compressed to high pressures, typically 3600 pounds per square inch (psi) to enable NGVs to store enough gas to have a driving range suitable for use in local driving applications; this is commonly referred to as CNG. Most NGVs are operated by centrally fueled fleets which operate private compressor stations at their base facilities. These compressor stations represent a substantial investment for fleets transitioning from diesel to natural gas. Larger fleets also maintain their own vehicle maintenance facilities; modifying a diesel service facility to enable servicing of NGVs requires substantial investments in ventilation and electrical equipment in order to mitigate risks associated with the volatility and flammability of CNG. CNG, however, has insufficient energy density to be suitable for long-haul operations. For these applications, natural gas is refrigerated to about minus 260°F to convert it to a liquid (known as liquefied natural gas, or LNG) with sufficient energy density for those applications.

Impacts of an LCFS

Assessment of changes to transport fuel makeup, supply and demand

In this section, we offer a qualitative assessment of the likely changes to transport fuel makeup as well as supply and demand as additional states adopt LCFS-style programs. Understanding the potential impacts of HF 2083 begins with a qualitative assessment of what changes can be made to the transportation fuels in MN to reduce deficit generation and increase credit generation given the current supply and demand for fuels, the current vehicle fleet, and the timeline to implement the changes required to meet the CI targets of the proposed statute.

The time which may be allocated for the Department of Commerce (DoC) to promulgate all of the regulations necessary for implementation of the proposed LCFS will be consumed with assignment of agency staff, the required process for the development and implementation of new regulations, implementation of required systems and processes and the necessary registration of regulated parties. The proposed legislation specifies that DoC utilize the GREET model with adaptation for MN for performing the required lifecycle analyses. This specification should enable DoC to draw on work already performed by California and Oregon in adapting the GREET model for their state LCFS programs. With that, the DoC will still need to perform the necessary adaptations and establish operational protocols for certification, validation, record-keeping, and reporting of credits; to do so, they will likely draw on analogous provisions in the California LCFS or Oregon CFP. Early engagement with stakeholders will be required to enable regulated parties to make timely plans for their participation and compliance with program requirements.

Importantly, existing state policies supporting ethanol and BD blending mean that these fuels are already widely utilized in the state. As the proposed program sets the baseline using the petroleum-only portion of the transportation fuels pool in 2018, existing levels of biofuel use will facilitate compliance in the early years of the program. The extent of the head start which this provides will depend on the assessment of CI for biofuel producers currently supplying MN’s in-state demands. A rough calculation based on the 2019 mix of gasoline-ethanol blends reported by the MN Department of Commerce,[35] biodiesel use in accordance with state regulations, sales of gasoline and diesel, and typical CI values suggests that the current fuel mix would provide about a 3% CI reduction versus the proposed baseline.[36]

With that uncertainty in mind, it is possible to qualitatively assess the potential options available for lowering the CI of transportation fuels covered by HF 2083.

  • Gasoline-fueled vehicles – These currently represent the largest demand for transportation fuels in the state. This demand is currently supplied predominantly by E10 gasoline with material presence of E15 and higher ethanol blends. The petroleum gasoline portion of these fuels is currently supplied by the two in-state refineries and imports from the Marathon Mandan, ND refinery, and the BP Whiting, IN refinery. It is also expected that the Husky refinery in Superior, WI will resume supply to portions of the state when it restarts. The ethanol portion of these fuels is supplied predominantly from ethanol plants in, or adjacent to, MN and blended at terminals in the state. The diversity of gasoline supply to the state, means that DoC will likely opt, as has CA and OR, to treat all petroleum-derived gasoline as having the same CI. Thus, lowering the CI of blended gasoline requires a combination of sourcing low-CI ethanol or increasing the ethanol content of the blending gasoline.
    • The pool of U.S. ethanol production has a wide range of CIs with the lowest CI product currently being segregated for use in CA or OR where it can be sold at a higher price than higher CI ethanol. The implementation of the proposed MN CFS would create incentive for MN to also receive lower CI ethanol, especially that produced in MN, if MN blenders offered prices to compete with CA and OR. Given the regulatory mandate of the MN CFS, it is reasonable to expect that the higher ethanol cost would be passed on to MN consumers. Over time, this premium for lower-CI ethanol would be expected to incentivize in-state ethanol producers to invest in lowering their CI; over time this rebalancing of supply and demand for lower-CI ethanol would erode the price premium.
    • The details of implementation of the GREET model for determination of CIs for fuels supplied to MN will be an important variable. As the large majority of the biofuels likely to be supplied to MN under the proposed CFS would be produced either in or near the state, the transportation component of the CI for use in MN will be smaller (more favorable) than for the same fuels supplied to CA or OR. Additionally, the state may choose to adopt a more recent version of the GREET model than currently used in CA or OR and thus report lower CIs due to improvements in agricultural and manufacturing yields which have occurred over time. Finally, MN may choose to use more recent data on indirect land use change (ILUC) than CA and OR, thus lowering what is currently a large component of the CI assessment for corn ethanol and soy biodiesel in CA and OR.
    • The most obvious option for increasing the ethanol content of MN gasoline would be to increase availability of E15, already available at 401 of the 2,068 retail stations in the state. The large majority of vehicles currently on the road in MN (all 2001 and newer light-duty vehicles) have EPA approval for use with E15.[37] Additionally, over 94% of new vehicles currently have manufacturer approval for use with E15[38] (the majority of exceptions are premium-required or premium-recommended vehicles where E15 octane, typically 88 R+M/2, does not meet the manufacturer’s minimum octane recommendation).[39] Broadened retail availability of E15 would require most retailers to invest in new or additional storage and dispensing equipment.[40] As ethanol is usually lower cost than gasoline, the cost savings from replacing E10 with E15 can offset the cost of the required retail investment.[41] The value of the CFS credits earned by E15 and E85 may also allow these fuels to be priced at larger discounts to E10, enabling volume growth through existing retail sites. A key unknown potentially reducing the ability to grow, or even retain, existing E15 volumes is the recent U.S. Court of Appeals ruling voiding EPA’s extension of the 1psi RVP waiver afforded E10 to also include E15.[42] (The U.S. ethanol industry is pursuing legal and legislative channels to reverse the effects of this ruling; this issue, which overrides any action the state of MN can take on its own, will likely take some time to come to a final decision.) A preliminary analysis suggests that conversion of the gasoline sales mix to predominantly E15 would result in about a 5% CI reduction versus the proposed baseline.[43]
  • Electric Vehicles (EVs) –The Atlas EV Hub[44] indicates 12,878 EVs registered in MN as of February 2020 including 7,322 battery EVs and 5,556 plug-in hybrid EVs. This compares to 1,836,831 automobiles and 1,221,681 trucks reported as registered in MN in 2019 by the Federal Highway Administration.[45] New EVs only represent a small fraction of new car sales[46] and new vehicles sold in the U.S. typically remain on the road for over fifteen years.[47] Accordingly, even if the market share of EVs were to grow rapidly, it would take many years for credits from electricity supplied into EVs to materially contribute credits to the CFS. The pace of growth of the EV fleet in MN will also depend on measures outside of the CFS, such as vehicle purchase incentives and support for installation of public charging facilities. The CA LCFS and the OR CFP require utilities to utilize a large portion of the revenues realized from credits earned for charging EVs to fund sales incentives for EVs and installation of EV infrastructure. HF 2083 does not contain provisions mandating such utilization; even if it did, however, the small size of the current EV fleet would not yield a very significant funding pool. Substantial growth in the EV population would also require upgrades to the MN electric grid to support wide availability of high-speed chargers. Also, while the MN power grid does currently contain a large share of nuclear, wind, and solar generation, it also has large share of coal-fired generation which limits the CI reduction which can be achieved with EVs. To materially grow the LCFS credit generation from EVs will require both grid upgrades and a reduction in the CI of the MN grid mix; these changes can be implemented gradually as the EV population will take a number of years to grow to material levels. As MN is currently a net importer of electricity, this would require a mix of new generation capacity being built in-state and reduction in the CI of electricity imported from out of state. Unlike the CA and OR programs (and the recently enacted WA program), HF 2083 does not contain provisions requiring IOUs to use the proceeds from LCFS credit sales to support electrification (e.g., investments in infrastructure and funding of rebates to EV buyers).
  • Diesel-fueled vehicles – The large majority of heavy-duty vehicles operating in MN are fueled with diesel fuel blended with BD as required by the existing per-gallon mandate. The petroleum portion of this fuel is sourced from the two in-state refineries and imports from the Marathon Mandan, ND refinery, and the BP Whiting, IN refinery. It is also expected that the Husky refinery in Superior, WI will resume supply to portions of the state when it restarts. In addition to existing levels of BD use, RD can be used neat or at any blend level (with or without BD in the mix) with petroleum diesel. Accordingly, increased blending of BD and RD in the diesel pool can be utilized with the current diesel fleet to generate substantial volumes of MN CFS credits in the near-term with volumes growing over time as U.S. production of RD is planned to rapidly increase. Most of the BD currently used in-state is sourced from the BD plants in MN with some imports from neighboring states. The nearest potential source of RD is the Marathon Dickinson plant in western ND; a number of additional plants are being developed across the U.S. and could potentially supply demand in MN.
  • Natural Gas Vehicles (NGVs) – MN currently has a small population of NGVs which are fueled with fossil natural gas. That fossil natural gas can be completely replaced with RNG without any vehicle or infrastructure modifications. California’s LCFS incentives have, as of the fourth quarter of 2020, resulted in over 98% of NGV demand being supplied by very low CI RNG. As RNG production, incentivized by the LCFS and the RFS has grown rapidly, there is a growing abundance of RNG production nationally (CA LCFS regulations address the challenge of delivery to in-state vehicles by allowing book-and-claim accounting to be used to associate RNG production anywhere in the U.S. to demand in California.) Accordingly, rapid penetration of RNG in the MN NGV fleet could be achieved through both in-state production and, if book-and-claim accounting is permitted, production in other states, provided the value of Minnesota CFS credits rises to the level necessary to enable it to compete with fossil natural gas. California, however, is relatively unique in the U.S. with respect to the high penetration of NGVs in the heavy-duty transportation sector; this is the result of long-standing state incentives and regulations aimed at driving diesel fleets to convert to NGVs. As a result, the credit generation opportunity currently accessible through RNG in MN is much smaller than has been the case in CA but could grow significantly if national LNG fueling infrastructure were to be built out, including along the major interstate corridors transiting MN (Interstates 90, 94 and 35).

In summary, the most likely near-term sources of MN CFS credit generation will be expansion of the already high levels of biofuels penetration in MN as mandated by current state law. These include attracting lower CI ethanol for use in gasoline as E10 blends, further increasing the availability of E15, and growing the share of BD and RD in the diesel fuel mix. Achieving these changes will require CFS credit prices to increase to levels needed to compete with CA and OR for supplies of the lowest CI ethanol, BD, and RD. Costs would be incurred to further increase the retail availability of E15; these costs would need to be borne by retailers, few of which are owned by fuel providers and many of which are small businesses operating on narrow margins – making that investment would require some combination of government grants or higher prices for consumers. While there is room for significant growth in the biofuels content of gasoline and diesel in MN, even very high penetration of E15 and substantial RD imports would not be sufficient to achieve the 20% CI reduction targeted in the proposed legislation. Thus, substantial growth in EVs will be required to achieve the 20% CI reduction target. For that to happen, however, would require a number of years to grow the EV population in the state, significant investment in the power grid and chargers, and an increasing share of low-carbon power generation in the state’s grid. RNG offers a readily accessible opportunity to reduce the emissions generated by the state’s NGVs, but the small existing NGV population makes that a limited opportunity. Growth of the NGV fleet would likely require a policy mix of fleet regulations and incentives for investment in NGVs and support infrastructure in addition to the LCFS; fleets can be expected to show reluctance to make any investment in NGVs so long as they see an evolving policy environment which will be pushing electrification.

Likely sources of supply for low-carbon fuels

MN is already a leading producer of biofuels and a large exporter of ethanol. Six of MN’s ethanol plants and one of its BD plants are currently registered to supply California’s LCFS program. All of the in-state ethanol and BD plants could supply in-state demand and, with the potential implementation of an LCFS, would be incentivized to invest in lowering the CI of their existing processes. MN could be expected to supply any likely increase in ethanol demand from existing in-state capacity. Increased demand for BD and any RD demand would likely need to be sourced from outside of the state. The large number of currently planned RD investments in the U.S. suggests that sourcing RD from elsewhere in the U.S. would not be a major concern. Imports of RD would likely come via rail; terminals may require upgrades in order to receive these imports. The current proposed legislation does not contain any provisions for funding additional E15 installations.

Growth in EVs in the state would require a number of years for the existing fleet to turnover; this would give time for the state to augment its electrical grid and install the required network of public charging facilities which would be needed. Securing further reductions in the CI of grid power in the state may require imposition of new RPS requirements beyond the levels currently mandated for 2025. The current proposed legislation does not contain any provisions for the required electrical distribution upgrades or incentives to drive sales of new EVs.

While the existing fleet of NGVs is small, it could be readily converted to use of RNG if operators of in-state landfills, wastewater plants, dairies and other livestock facilities see LCFS credit values sufficient to incentivize investment in RNG production and natural gas pipeline regulations made provision for RNG of appropriate quality to be injected into the natural gas grid. Growth in the NGV fleet is likely to be minimal in the absence of incentives for diesel fleets to convert and guarantees that they will not subsequently be required to electrify before they had the chance to recover the required investments.

Availability and cost of transport fuel to consumers

The cost to MN consumers to achieve the 20% CI reduction by 2035 as proposed in HF 2083 will depend on key factors including:

  • The calculation methodologies adopted by the DoC; this report assumes that the methodologies will be substantially similar to those in place for the California LCFS.
  • The rate at which the MN vehicle fleet turns over to alternative technologies such as EVs, FCVs, and NGVs. This may be influenced by mandates and incentives other than the CFS.
  • The number and size of additional states which may adopt similar programs in this timeframe. Further growth in the number of LCFS states will drive competition for potentially limited feedstocks and low-CI fuels.

Looking at the current California LCFS program as a benchmark for comparison, Stillwater has recently estimated LCFS costs at 23.6 cents per gallon of gasoline BOB and 23.3 cents per gallon for ULSD[48] while targeting an 8.75% CI reduction in 2021.

Factors which may cause the MN LCFS to be more costly to achieve the proposed 20% CI reduction by 2035:

  • Each increment of reduction becomes increasingly costly as it requires bigger changes in the fuel mix. Conservatively assuming that the increase is linear going from 8.75% to 20% CI reduction, this would increase the estimate to 54 cents per gallon for gasoline BOB and 53 cents per gallon for ULSD.
  • The MN vehicle fleet currently has a much smaller proportion of EVs, FCVs, and NGVs than does California’s. If the market share of those vehicles does not catch up with California levels, the MN program would not benefit from the zero and negative CI fuels which can be used to fuel those vehicles. In the fourth quarter of 2020, these fuels (RNG, electricity, and hydrogen) accounted for over 31% of LCFS credit generation,[49] and this share has been steadily growing. If the MN vehicle fleet does not transition to a mix similar to that of CA, then MN would need to compensate by further accelerating retail availability of E15 and blending a larger share of BD and RD into the diesel pool.
  • The current proposal includes aviation and marine fuels. However, the legislature may ultimately decide to remove them from the proposed program after reviewing jurisdictional issues.[50]
  • Washington state has recently enacted an LCFS program scheduled to take effect in 2023. Other state legislatures, such as New York and New Mexico are also considering LCFS programs in their current sessions. The implementation of additional state programs would increase demand for the lowest CI fuels, driving up compliance costs in all jurisdictions. Additionally, Canada’s national LCFS program, scheduled to take effect in December 2022 will also be competing for some of the same low-carbon fuels.

There are also factors which may serve to reduce the potential compliance costs of the proposed MN program relative to what has been observed in CA:

  • The choice to use petroleum fuels only (based on 2018) as the baseline under HF 2083 means that initial CI reductions for the first couple years of the proposed program can be attributed to just the continuation of existing biofuels use in the state.
  • E15 is already widely available in MN (currently offered at nearly 20% of retail gasoline stations) whereas CA does not currently permit use of E15. While current market availability of E15 is small, recent relaxation of EPA requirements for E15 have lowered the cost for retailers to expand availability and implementation of the proposed LCFS would create a strong incentive for increasing availability. The use of E15 in place of E10 reduces the number of deficits generated while increasing credit generation, thus lowering compliance costs. A potential barrier to the growth in E15 sales is the recent DC Circuit Court ruling which struck down EPA’s extension of the E10 1psi RVP waiver to E15; the renewable fuels industry is currently appealing this decision.
  • As shown in Figure 4, MN has a higher share of diesel fuel in its transportation fuel mix than does CA. Experience in CA has demonstrated that large shares of BD and RD can be readily incorporated in diesel fuel with minimal investment in terminalling and logistics infrastructure. Substantial investments in RD production capacity are already being made around the U.S. The primary limitation to this potential compliance option is a potential scarcity of suitable, low-carbon feedstocks to enable continued growth in BD and RD production.

Figure 4. Transportation Fuel Demand 2018 (thousand barrels)

Source: EIA[51], Stillwater analysis

[1] HF 6 is the omnibus commerce bill signed by the Governor on June 26, 2021. The proposed LCFS (included in HF 2083) would be administered by the Department of Commerce.

[2] The definition of baseline to only include petroleum fuels is particularly relevant in Minnesota due to the existing high levels of ethanol and biodiesel use driven by existing state policies.

[3] The Greenhouse gases, Regulated Emissions, and Energy use in Technologies (GREET) Model has been developed by Argonne National Laboratories ( It is a lifecycle analysis model widely used in the U.S. for evaluation of transport sector GHG emissions. Versions of the GREET model have been adapted for use in the California LCFS and Oregon CFP programs.

[4] CA and OR do allow credits to be generated from the use of low CI aviation and marine fuels but no deficits are generated for the petroleum portions of those fuels.

[5] The refinery was shut down following a major explosion and fire on April 26, 2018. Rebuilding is currently in progress with a re-start currently estimated in 2023.

[6] U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, Private NAICS 447 Gasoline Stations, All counties in Minnesota,

[7] U.S. EPA Part 80 Fuels Programs Registration List available at

[8] U.S. Fuel Ethanol Plant Production Capacity, September 25, 2020,

[9] EIA Biodiesel producers and production capacity by state, December 2020,

[10] Minnesota Statutes 239.761 and 239.791.

[11] Minnesota Statutes 239.75 and 239.77.

[12] A minimum of 10% applied from April 1st through 14th.




[16] Per Minnesota Statute 239.791, exemptions are limited to gasoline used for aviation, marine vessels, motor sports racing, collector vehicles, and off-road use. Ethanol-free gasoline must meet premium specifications.

[17] Available at


[19] Stillwater analysis.


[21] Stillwater analysis; assumes total diesel volume is consumed evenly throughout the year.


[23] Gasoline Gallon Equivalents, 119.53 MJ.


[25] The minimum blend percentage varies seasonally with a 20% requirement from April 15th through September 30th, a 5% minimum from October 1st through March 31st, and a 10% minimum from April 1st through April 14th.

[26] U.S. Fuel Ethanol Plant Production Capacity, September 25, 2020,

[27] Minnesota Electricity Profile 2019,

[28] EIA State Energy Profile for Minnesota,


[30] The largest utility in the state and owner of the nuclear power plants.

[31] Minnesota Renewable Energy Standard, Updated June 15, 2018,





[36] Stillwater analysis, August 17, 2021.

[37] E15 is not approved for use in motorcycles, non-road engines, and heavy-duty gasoline engines. Accordingly, E10 or E0 would need to be retained in the marketplace for those applications.


[39] While there is nothing preventing the production and supply of premium E15, it is not currently done due to limited perceived demand.

[40] This investment is relatively modest for new or rebuilt stations but can be substantial for existing stations depending on their existing equipment. Many existing retail installations around the U.S. were partially funded through Federal or state grants.

[41] Pricing of E15, where currently available in the U.S., is typically five cents per gallon below E10 regular grade offered at the same site. In many cases, state incentives for E15 also offset the retailers’ costs.


[43] Stillwater analysis, August 17, 2021. This analysis assumes that the share of E15 increases from 2019 levels of 3.4% of sales to 92.4% of sales (the share of sales for E10 in 2019) while E10 sales decrease to a 3.4% share.


[45] State Motor Vehicle Registrations – 2019 as reported in November 2020,

[46] In 2019, U.S. new car sales were 17 million vehicles ( and only 331,000 of those vehicles were EVs (, for a 1.9% share.

[47] The U.S. car and truck fleet, as reported by the Federal Highway Administration for 2019 was about 267 million vehicles and new light-duty vehicle sales in 2019 were 17.1 million vehicles ( implying an average lifetime of 15.6 years assuming a steady vehicle population (267 million vehicles ÷ 17.1 million vehicles/year = 15.6 years)

[48] This is for CARBOB to produce California Reformulated Gasoline when blended with 10% ethanol and CARB ULSD, respectively. Costs cited include the current cost of the incremental crude provisions of the regulations. Full report can be found at:

[49] In 4Q2020, RNG in California generated 0.55 million credits, electricity 0.81 million credits, and hydrogen 0.01 million credits for a total of 1.37 million credits out of total credit generation of 4.34 million.

[50] The state does not have jurisdiction over aviation fuels; they could, as California does, allow for optional credit generation for renewable aviation fuels supplied to aircraft fueled in the state. Similar issues arise for marine fuels on vessels operated outside of state waters. Additionally, U.S. EPA prohibits use of E15 or higher ethanol blends in gasoline-powered watercraft.

[51] EIA State Energy Demand System,

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