Minnesota Clean Transportation Standard Act – Take Two!

March 14, 2023 By , , ,

March 14, 2023

Note: This post was edited on February 12, 2024 to update and elaborate on our calculations/methodology.

In the U.S., several programs aim to reduce greenhouse gas (GHG) emissions per unit of energy of fuels used in transportation. California, Oregon, and Washington all have low carbon fuel standard (LCFS) style 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. Minnesota, New Mexico, New York, Vermont, and Illinois have introduced LCFS-style bills in the 2023 legislative session.

In this memo, Stillwater examines the potential impacts of implementing an LCFS-style program in Minnesota on the cost of fuels to consumers. We begin by highlighting the differences between Minnesota’s House File 2083 (HF 2083, referred to as the Future Fuels Act or FFA) as introduced in the state House of Representatives during the first session of 2021 and Senate File 2584, the Clean Transportation Standard Act (SF 2584, or CTSA) which was introduced into the Minnesota Senate on March 6, 2023.[footnote 1] Finally, we discuss the potential impacts on the cost of fuel to consumers in Minnesota.

As of this writing, the Minnesota CTSA is still in Committee – the Senate Transportation Committee – and has yet to be passed into law. For purposes of this report, it is assumed that the CTSA as outlined in SF 2584 is enacted by the Minnesota Legislature in its 2023 session, signed by the Governor, and enabling regulations are promulgated in a timely manner to allow program commencement on January 1, 2025. The program outlined by SF 2584 largely mimics the California LCFS and the Oregon Clean Fuels Program (CFP) with key differences being a different choice of baseline year and a different carbon intensity (CI) reduction schedule, both consistent with a later starting date than the California and Oregon programs. Importantly, SF 2584 currently contains important provisions restricting potential credit sources and enabling consideration of certain low-carbon agricultural practices in assessing carbon intensity.

The cost to Minnesota consumers to achieve the 25% CI reduction by 2030, 75% CI reduction by 2040, and the 100% CI reduction by 2050 as proposed in SF 2584 will depend on key factors including the technical calculation methodologies adopted by the Minnesota Pollution Control Agency (PCA); the rate at which the MN vehicle fleet turns over to alternative technologies such as electric vehicles (EVs), hydrogen fuel cell vehicles (FCVs), and natural gas vehicles (NGVs); and the number and size of additional states which may adopt similar programs in this timeframe. Stillwater’s estimates of these costs, assuming adoption of a program similar to California’s and Oregon’s are presented herein.

Overview of the 2021 proposed legislation

Minnesota has yet to pass legislation to establish an LCFS program. Stillwater Associates previously reviewed[2] House File 2083 (HF 2083) as introduced to the state House of Representatives during the 2021 session.[3] HF 2083 was referred to as the Future Fuels Act (FFA).

Key provisions and omissions of HF 2083 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 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.[4]
  • 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[5] model adapted to MN. The calculation must be consistent for all fuel types; science and engineering-based; and reflect differences in drive train efficiencies.
  • The regulations are required to be fuel neutral.
  • 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.
  • 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 renewable natural gas (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.

Key items not covered in the bill included:

  • No defined implementation date was set. This will be added before the bill advanced to a vote.
  • No specified annual schedule of CI reductions. A minimum CI reduction of 20% by 2035 is stipulated and to be achieved with steady annual reductions. The Commissioner appeared 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, Oregon, and Washington programs.
  • No specification that low-CI fuels be supplied for end-use in MN in order to generate credits.

Additionally, the scope of the 2021 legislation appeared to include aviation and marine fuels. The California, Oregon and Washington programs exclude deficit generation from these fuels due to limitations on the states’ authority under federal law.[6] The legality of MN’s inclusion of jet and marine fuels may need to be addressed before any legislation is submitted for a vote.

Overview of the 2023 proposed legislation

Senate File 2584 (SF 2584) was introduced into the 2023 session of the Minnesota legislature by Senators David Dibble, Foung Hawj, and Erin Murphy on March 6, 2023. As of this writing, it has been referred to the Senate Transportation Committee where it is scheduled for a hearing on March 9, 2023.

Key provisions include:

  • The program is to be administered by the Commissioner of the Minnesota Pollution Control Agency (PCA) who is directed to consult with the state departments of Commerce, Transportation, and Agriculture.
  • The Clean Transportation Standard (CTS) is to deliver a 25% CI reduction across all transportation fuel supplied to Minnesota, versus and 2018 baseline, by 2030; a 75% CI reduction by 2040; and a 100% reduction by 2050.
  • The term “transportation fuel” is broadly defined to include electricity and gaseous or liquid fuels used to propel motor vehicles, including on-road, non-road, rail, marine, and aviation.
  • The CI reductions are to be implemented through an annual schedule of steadily decreasing CI targets with consideration given to cost of compliance, available technologies, fuel quality and availability, and the impact on the state’s overall GHG reduction goals.
  • The baseline calculation only considers the petroleum portion of the 2018 transportation fuel supply. This is significant as Minnesota in 2018 had very high penetration of ethanol in the gasoline pool and biodiesel (BD) in the diesel pool due to state mandates.
  • CI determinations are to be made using the most current version of the GREET model adapted to MN. The pathway determination process is directed to be consistent for all fuel types, based on science and engineering, reflect drivetrain efficiencies, and account for on-site energy use for carbon capture technology. The Commissioner is directed to consult with the state departments of Agriculture, Transportation, and Commerce in making pathway determinations and may coordinate with third-party entities or other states.
  • Deficit generators may achieve compliance through production or import of credit generating fuels or the purchase of credits from other parties.
  • Credits are generated when a low-CI fuel is produced, imported, or provided for use in MN with provisions designed to prevent double-counting of credits.
  • Credits are allowed to be banked or traded with transaction fees being allowed. Provisions must be put in place to verify the validity of credits and deficits for each fuel provider.
  • Prohibitions include credit generation for CCS utilized for enhanced oil recovery, production of biofuels from feedstocks grown on land with less than five consecutive years of cropping history, and RNG produced from new or expanded agricultural livestock production facilities.
  • A five percent credit premium is permitted for cropland-derived biofuels utilizing soil-healthy farming practices and best practices for fertilizer management. A ten percent credit premium is permitted from cropland-derived biofuels produced on acreage utilizing continuous living cover cropping systems. Eligibility for such credits must be determined annually in collaboration with other state agencies. Biofuel producers may also petition for pathways based on analysis of their specific practices.
  • Credit generation is permitted for electric or alternative fuels and infrastructure which pre-date this legislation.
  • Procedures must be implemented to generate credits for residential EV charging. All revenues generated from residential EV charging credits are to be used to promote transport electrification; 60% of these revenues must specifically be used to support electrification for disadvantaged, low-income, and rural communities.
  • The implementation date is currently a blank that will need to be filled in before this legislation can be adopted.
  • Aviation fuels are specifically exempted due to federal preemption but usage of alternative fuels in aviation can earn credits.
  • Fuel providers are required to report annually on compliance with these regulations.
  • The Commissioner must report back to the Legislature on implementation within 48 months of the program’s effective date. Program data is required to be made publicly available.
  • The Commissioner must perform a detailed review of the CTS at least once every five years.

Key Differences Between the Two Proposals

There are a number of important differences between the two proposals. These changes appear to reflect stakeholder consultations held since the initial 2021 bill was drafted. Overall, the current bill is somewhat more detailed with changes primarily designed to assuage concerns of environmental stakeholders. Remaining unspecified issues are primarily commercial concerns and potentially amenable to definition as part of the regulatory implementation process.

  • SF 2584 places program administration with the Commissioner of the PCA rather than with the Department of Commerce as specified in HF 2083. Historically, fuel regulations, such as Minnesota’s ethanol and biodiesel mandates have been managed by Commerce. Placement of the proposed CTS with PCA appears designed to facilitate coordination with other state climate programs.
  • SF 2584 substantially increases the depth and pace of the required CI reductions from a 20% reduction in 2035 specified in HF 2083 to a 25% reduction in 2030 specified in SF 2584 with further reductions to 75% in 2040 and 100% in 2050. Both measure grant authority to require more stringent targets.
  • SF 2584 specifically excludes aviation fuels in recognition of federal preemption. This factor was not recognized in HF 2083. Still unrecognized are federal preemption issues with respect to interstate and international rail and marine fuels.
  • SF 2584 specifically allows coordination with third-party entities or other states to review and approve fuel pathways. Harmonization with other jurisdictions should simplify compliance for all regulated parties, particularly as more states consider enacting similar programs.
  • SF 2584 permits the assessment of fees on credit transactions. The Washington state program and the proposed New Mexico legislation permit registration fees to fund program management while California and Oregon do not have any direct program fees.
  • SF 2584 adds prohibitions on credit generation from CCS used for enhanced oil recovery; biofuels from feedstocks grown on lands without at least five consecutive years of cropping; and RNG from new or expanded livestock operations. These appear to be included to address issues which have been raised by stakeholders representing environmental interests. The restriction on crop lands should enable the MN adaption of the GREET model to include reductions in land use change assessments.
  • SF 2584 adds provisions to grant additional credits by agricultural practices designed to improve soil carbon and minimize fertilizer run-off issues. Biofuel stakeholders have sought these credit-generating opportunities in other jurisdictions; including them, in principle, should enable production of lower CI biofuels and encourage the development of cover crops with potential to produce additional feedstocks.
  • SF 2584 contains more specifics to promote electrification, including a requirement for EV residential charging revenues to be used to promote electrification.

Overall, the more rapid CI reduction schedule mandated by SF 2584 is expected to increase program costs relative to what would occur if HF 2083 were to be implemented. The requirement that investor-owned utilities use credit revenues to support transportation electrification under SF 2584 may mitigate some of these costs; however, since the current penetration of EVs in Minnesota is low, the differences may be small in the early years of the program.

Unlike other LCFS style programs, SF 2584 in its current form still omits any cost containment provisions, such as a credit clearance market or price cap. It does not impose any requirements on who may hold credits. It also does not grant any specific authority for PCA to waive or adjust program requirements if warranted by either short-term market disruptions or long-term feasibility issues.

Impacts of a Minnesota LCFS – Availability and cost of transport fuel to consumers

The cost to Minnesota consumers to achieve the 25% CI reduction by 2030 as proposed in SF 2584 will depend on key factors including:

  • The technical calculation methodologies adopted by the PCA; this report assumes that the methodologies will be substantially similar to those in place for the California LCFS.
  • The rate at which the covered Minnesota vehicle fleet turns over to alternative technologies such as EVs, FCVs, and NGVs. This may be influenced by mandates and incentives other than the CTS. The addition of a requirement for residential EV charging credit revenues to be invested in transportation electrification may accelerate the transition to EVs over the long term; short-term impacts are expected to be more sensitive to implementation of federal EV incentives.
  • 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 low-CI fuels.
  • The prohibition on credit generation for CCS used in enhanced oil recovery will reduce opportunities for lowering the CI of biofuel and hydrogen production while precluding a key measure to increase availability and reduce cost of the Bakken crude used in refineries supplying the Minnesota market. The prohibitions on feedstocks from newly cropped land and RNG from new or expanded livestock opportunities will likely result in shuffling of agricultural commodities and RNG, adding costs from this inefficiency without materially changing land use or the growth of livestock operations. The potential costs attributable to these factors are not readily quantified and, thus, are excluded from this high-level assessment of potential program costs.
  • The opportunities for additional credit generation linked to agricultural practices may be an important incentive for commercializing the specified practice; the potential impact on consumer costs is not quantified in this high-level assessment.

Since our 2021 review of HF 2083, the value of California LCFS credits has fallen from around $200/MT to recent values of $67/MT. This has occurred largely due to rapid growth in the supply of renewable diesel (RD), very low CI RNG, and growth in the EV share of the light-duty vehicle fleet even as the CI benchmark has ratcheted from an 8.75% reduction in 2021 to an 11.25% reduction in 2023. As of March 7, 2023, Stillwater estimates the cost of the LCFS to be around 11 cpg of petroleum gasoline and diesel.

Importantly, The California Air Resources Board (CARB) is currently in the process of amending the LCFS.   The proposed amendments will significantly accelerate the required CI reductions in future years and extend the CI reduction schedule to a 90% CI reduction requirement in 2045. Stillwater expects that market prices for LCFS credits will firm as the approval process advances.

The CI reduction standards proposed in SF 2584 (25% in 2030, 75% in 2040, and 100% in 2050) are far more stringent than what was proposed in 2021’s HF 2083 (20% in 2035); all else being equal, this means that more CTS credits will be required for every gallon of petroleum gasoline and diesel sold in the state and, thus, creates additional upward pressure on the consumer cost of each gallon of gasoline or diesel purchased. The price of those credits will be driven by demand for the same low-carbon fuels as those being used in California and elsewhere where LCFS style programs are in place. Factors which may cause the Minnesota CTS to be more costly than the current cost of the California LCFS program include:

  • Each increment of reduction becomes increasingly costly as it requires bigger changes in the fuel mix. Conservatively assuming that the increased CI standards and growing demand for low-carbon fuels does not increase credit prices above currently observed levels results in a minimum estimate of 20 cpg for the petroleum portion of gasoline-ethanol blends and 23 cpg for ULSD for the proposed 25% CI reduction standard in 2030. These would, conservatively, increase to a minimum of 61 cpg of gasoline BOB and 68 cpg of ULSD for the 75% CI reduction standard in 2040.
  • More realistically, the price of credits is expected to increase as demand for low-carbon fuels and credits in all LCFS markets increases and the standards in Minnesota become more stringent. Using a proprietary Stillwater correlation based on the historical relationship between California LCFS and Oregon CFP prices, we expect Minnesota CTS credits to cost approximately $151/MT in 2030 with the proposed 25% CI reduction. These credit prices would amount to 45 cpg of petroleum gasoline and 51 cpg of petroleum diesel in 2030. We are not able to do similar calculations for the 75% CI reduction in 2040 or 100% CI reduction in 2050 as achieving those reductions will fundamentally change the nature of compliance; most current ethanol, BD, and RD production pathways would yield deficit-generating fuels at those deep CI reductions. Estimation of the costs of decarbonization of these renewable fuel pathways sufficient to make them credit-generating at these CI reduction targets is outside the scope of this analysis.
  • The choice of 2018 as the baseline year under SF 2584 but counting only petroleum-derived fuels is roughly similar to California’s use of 2010 as the baseline as California’s baseline has no BD or RD in the diesel pool and 10% ethanol in the gasoline pool.
  • The Minnesota vehicle fleet currently has a much smaller proportion of EVs, FCVs, and NGVs than does California’s. (As of December 31, 2021 the total population of EVs in MN was estimated at 30,000. For reference, total light-duty vehicle registrations in Minnesota in 2018 is reported by the U.S. Department of Transportation as over 5.1 million.[7]) If the market share of those vehicles does not catch up with California levels, the Minnesota program would not benefit from the zero- and negative-CI fuels which can be used to fuel those vehicles. In the third quarter of 2022, these fuels (RNG, electricity, and hydrogen) accounted for nearly 42% of LCFS credit generation in California,[8] and this share has been steadily growing. If the Minnesota vehicle fleet does not transition to a mix similar to that of California, then Minnesota would need to compensate by accelerating retail availability of E15 and blending a larger share of BD and RD into the diesel pool.
  • While jet fuel does not generate deficits in the California LCFS or the proposed Minnesota CTS, California allows renewable jet (RJ, also known as sustainable aviation fuel, SAF) to generate credits. To date, this has only been a minimal source of credits generated for the LCFS but is expected to grow in the coming years with the adoption of RJ/SAF incentives in the 2022 federal Inflation Reduction Act. While this could be a substantial credit generator in California, due to the large jet fuel demand for trans-Pacific and coast-to-coast air travel out of Los Angeles and San Francisco, demand for jet fuel in Minnesota is much smaller, as shown in Figure 1 below.
  • Washington state’s LCFS program has now taken effect. Other state legislatures, such as New York, Vermont, Illinois, and New Mexico are also considering LCFS programs in their current sessions. The implementation of additional state programs increases competition for the lowest CI fuels, driving up compliance costs in all jurisdictions.

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

  • Minnesota has already approved the use of E15 (California has not), and distribution is widespread and growing. While current market share of E15 is small, potential relaxation of EPA requirements for E15 have lowered the cost for retailers to expand availability and implementation if the proposed CTS were to create a strong incentive for increasing market share. The use of E15 in place of E10 reduces the number of deficits generated while increasing credit generation, thus lowering compliance costs.
  • As shown in Figure 1, MN has a much higher share of diesel fuel in its transportation fuel mix than does CA and all terminals supplying diesel to Minnesota are equipped for biodiesel blending as required by the state’s blending mandate.[9] Experience in CA has demonstrated that large shares of BD and RD can be readily incorporated in diesel fuel with minimal investment in terminaling and logistics infrastructure. 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 1. Transportation Fuel Demand 2018 (thousand barrels)

Source: EIA, Stillwater analysis

Additionally, compliance with the 75% CI reduction standard proposed for 2040 and the 100% CI reduction standard proposed for 2025 far exceed what has been mandated in any other LCFS program.[10] At these CI reduction levels, conventional biofuels become deficit-generating. Compliance in this environment will depend on approval of extremely low or negative CI pathways for liquid fuels along with the pace of electrification of the Minnesota vehicle fleet and the pace at which the Minnesota power grid decarbonizes.

  • According to the 2022 GREET Model, the CI of the Minnesota power mix is 146,002 gCO2e/mmBTU or nearly double California’s 74,127 gCO2e/mmBTU.
  • Minnesota’s vehicle fleet of over 5.1 million vehicles as of 2020[11] of which only 30,000 vehicles are EVs. Assuming a constant fleet size (new purchases each year equal retirements), an average vehicle life of 12 years, and the state achieving the new vehicle sales targets of the California Advanced Clean Cars II (ACC2) Rule[12], the Minnesota vehicle fleet can be expected to be over 97% internal combustion engine (ICE) vehicles in 2026, 50% ICE vehicles in 2040, and 28% ICE vehicles in 2050.
  • Currently, the lowest CI liquid fuel pathway in the California LCFS program is used cooking oil (UCO) biodiesel with a CI of 12 gCO2e/MJ. Even this fuel would only be a minor credit generator at the 75% CI reduction standard proposed for 2040 and a deficit generator at the 100% CI reduction standard proposed for 2050.

In summary, the potential costs of the proposed Minnesota CTS cannot be precisely estimated until regulations are finalized. Based on the factors described above, these costs would be expected to be significantly higher than the current costs of the California LCFS due to the more stringent CI reduction requirement (25% in 2030 and 75% in 2040 compared to CA requiring an 11.25% CI reduction in 2023) and the set of factors described above, specific to the Minnesota market, which would make the targeted CI reductions more difficult to achieve than will be the case in California. With these limitations in mind, we consider a few options for estimating the potential impact of SF 2584 utilizing data from the California LCFS program.

The current per-gallon costs of the California LCFS program can be calculated based on:

  1. The 2023 average credit price of $73.00/MT;
  2. The baseline CIs of CARBOB and CA ULSD, 100.82 gCO2e/MJ and 100.45 gCO2e/MJ, respectively;
  3. The 2023 gasoline and diesel benchmarks of 88.25 gCO2e/MJ and 89.15 gCO2e/MJ, respectively; and
  4. The specified energy densities of CARBOB and CA ULSD, 119.53 MJ/gal and 134.47 MJ/gal, respectively.

With these parameters, we first calculate the number of deficits generated per gallon of CARBOB and CA ULSD:

  • CARBOB Deficits/gal = (100.82 – 88.25) g/MJ X 119.53 MJ/gal X 10-6 MT/g = 0.001502 MT/gal
  • CA ULSD Deficits/gal = (100.45 – 89.15) g/MJ X 134.47 MJ/gal X 10-6 MT/g = 0.001520 MT/gal

and, then, the per-gallon costs of those deficits:

  • CARBOB cost/gal = 0.001502 MT/gal X $73.00/MT X 100 cts/$ = 11 cts/gal
  • CA ULSD cost/gal = 0.001520 MT/gal X $73.00/MT X 100 cts/$ = 11 cts/gal

For our lower estimate of the potential increase in per-gallon costs associated with SF 2584, Stillwater makes the following assumptions:

  1. Minnesota credit prices remain equal to 2023 California credit prices ($73.00/MT) despite the increased credit demands due to the 25% CI reduction for Minnesota in 2030 and 75% CI reduction in 2040 compared to the 11.25% 2023 CI reduction requirement for California in 2023;
  2. Minnesota assigns the same baseline CIs to CBOB and ULSD as California currently assigns to CARBOB and CA ULSD (100.82 gCO2e/MJ and 100.45 gCO2e/MJ, respectively); and
  3. Minnesota uses the same energy densities for CBOB and ULSD as California currently assigns to CARBOB and CA ULSD (119.53 MJ/gal and 134.47 MJ/gal, respectively).

With these parameters, we first calculate the number of deficits generated per gallon of CBOB and ULSD in 2030:

  • CBOB Deficits/gal = (100.82 – 75% X 100.82) g/MJ X 119.53 MJ/gal X 10-6 MT/g = 0.003013 MT/gal
  • ULSD Deficits/gal = (100.45 – 75% X 100.45) g/MJ X 134.47 MJ/gal X 10-6 MT/g = 0.003377 MT/gal

and, then, the per-gallon costs of those deficits:

  • CBOB cost/gal = 0.003013 MT/gal X $73.00/MT X 100 cts/$ = 22 cts/gal
  • ULSD cost/gal = 0.003377 MT/gal X $73.00/MT X 100 cts/$ = 25 cts/gal

Repeating the same calculations for the 75% proposed CI reductions in 2040:

  • CBOB Deficits/gal = (100.82 – 25% X 100.82) g/MJ X 119.53 MJ/gal X 10-6 MT/g = 0.009038 MT/gal
  • ULSD Deficits/gal = (100.45 – 25% X 100.45) g/MJ X 134.47 MJ/gal X 10-6 MT/g = 0.010131 MT/gal
  • CBOB cost/gal = 0.009038 MT/gal X $73.00/MT X 100 cts/$ = 66 cts/gal
  • ULSD cost/gal = 0.010131 MT/gal X $73.00/MT X 100 cts/$ = 74 cts/gal

Using the same approach, we next estimate the potential costs if LCFS credit prices recover to their all-time high of $218/MT achieved on February 3, 2020. This price recovery is deemed to have a high probability by 2030 based on increasing stringency of LCF requirements for current programs in California, Oregon, and Washington and potential expansion of the number of states implementing such programs. Based on that assumption, the per-gallon costs of deficits in Minnesota in 2030 would be:

  • CBOB cost/gal = 0.003013 MT/gal X $218.00/MT X 100 cts/$ = 66 cts/gal
  • ULSD cost/gal = 0.003377 MT/gal X $218.00/MT X 100 cts/$ = 74 cts/gal

Based on that same price assumption, the per-gallon costs of deficits in Minnesota in 2040 would be:

  • CBOB cost/gal = 0.009038 MT/gal X $218.00/MT X 100 cts/$ = 197 cts/gal
  • ULSD cost/gal = 0.010131 MT/gal X $218.00/MT X 100 cts/$ = 221 cts/gal

For our maximum credit price estimate, we assume that, by 2030, LCFS credit prices increase to our estimate of the credit price cap, $311.70/MT, and continue increasing to the estimated price cap of $399.00 in 2040.[13] This price recovery is deemed to have a moderate probability by 2030 and a high probability by 2040 based on increasing stringency of LCF requirements for current programs in California (including currently proposed amendments),[14] Oregon, and Washington and potential expansion of the number of states implementing such programs. Based on that assumption, the per-gallon costs of deficits in Minnesota in 2030 would be:

  • CBOB cost/gal = 0.003013 MT/gal X $311.70/MT X 100 cts/$ = 94 cts/gal
  • ULSD cost/gal = 0.003377 MT/gal X $311.70/MT X 100 cts/$ = 105 cts/gal

Based on that same price approach, the per-gallon costs of deficits in Minnesota in 2040 would be:

  • CBOB cost/gal = 0.009038 MT/gal X $399.00/MT X 100 cts/$ = 361 cts/gal
  • ULSD cost/gal = 0.0101312 MT/gal X $399.00/MT X 100 cts/$ = 404 cts/gal

For an alternative approach to estimating the potential increase in per-gallon costs associated with SF 2584, Stillwater makes the following assumptions:

  1. LCFS credit prices remain at the 2023 average value of $73.00/MT;
  2. RD produced from soybean oil will be the marginal source of SF 2584 credits,
  3. Soy RD in both California and Minnesota will have a CI of 55 gCO2e/MJ and be assigned an energy density of 129.65, and
  4. Minnesota SF 2584 credits will need to be priced at a level which will provide the same per-gallon value as it currently receives under the California LCFS.

With these assumptions, we first calculate the current LCFS credit value of 55 CI Soy RD:

  • Soy RD credit value = (89.15 – 55.00) gCO2e/MJ X 129.65 MJ/gal X $73.00/MT X 10-6 MT/g X 100 cts/$ = 32 cts/gal

For Soy RD to earn the same 32 cts/gal in credits in Minnesota in 2030 as it earns in California in 2023

  • 32 cts/gal = (75% X 100.45 – 55) gCO2e/MJ X 129.65 MJ/gal X 10-6 MT/g X 100 cts/$ X P
    • Where P = predicted Minnesota credit price in 2030

Solving for P

  • P = 32 cts/gal /[ (75% X 100.45 – 55) gCO2e/MJ X 129.65 MJ/gal X 10-6 MT/g X 100 cts/gal ]
  • P = $122.56/MT

Next, we calculate the 2030 per-gallon costs based on this predicted Minnesota credit price:

  • CBOB cost/gal = 0.003013 MT/gal X $122.56/MT X 100 cts/$ = 37 cts/gal
  • ULSD cost/gal = 0.003377 MT/gal X $122.56/MT X 100 cts/$ = 41 cts/gal

This methodology does not work in 2040, as Soy RD will have a CI (55 gCO2e/MJ) which is greater than the estimated diesel benchmark of 25.11 gCO2e/MJ[15] and, thus, would be a deficit-generating fuel.

This alternative estimate is also seen as conservative as it assumes that California LCFS credit prices will not increase from current levels even as existing regulations in California, Oregon, and Washington become much more stringent and, potentially, other states implement LCF programs. This conservative range of potential costs is summarized in Table 1 below.

A few key points for interpreting these cost estimates:

  1. These estimates of potential program costs are based on different estimates of the price of CTS program credits in 2030 and 2040 and calculating the number of credits which suppliers of CBOB and ULSD will need to acquire for each gallon of those fuels which they supply to the Minnesota market.
  2. This analysis assumes that fuel suppliers pass the program costs on to consumers.[216]
  3. These are fixed-point estimates of the annual-average cost in 2030 and 2040 as these are the years in which the proposed legislation mandates a 20% and a 30% CI reduction, respectively; we assume that the supply of credits in those years will equal demand. We expect that credit prices and, hence, per-gallon program costs, will ramp up from zero prior to the first year of program implementation to the estimated value in 2030; the pace at which the cost ramps up will depend on the schedule of annual CI reduction targets adopted by the PCA when they promulgate the regulations necessary to implement SF 2584. From 2030, the per-gallon program costs would also be expected to ramp up to the estimated value in 2040 at a pace dependent upon the annual schedule of CI reduction targets to be established by the PCA.
  4. Costs would be expected to continue increasing in subsequent years if the state acts to demand deeper CI reductions.

Actual credit prices in the market would be expected to vary over the course of the year depending on factors including the actual and perceived supply/demand balances for program credits; the evolving outlook of market participants for the supply/demand balance for program credits in subsequent years; news and rumors of potential amendments to the regulations; and the frequency and detail with which the PCA publishes data on credit and deficit generation, credit transaction volumes, and credit prices.

Table 1. Potential Costs of Proposed Minnesota SF 2584 Clean Transportation Standard

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[1] A companion measure, HF 2602 was introduced into the Minnesota House of Representatives on the same date. The two measures appear to be substantially the same. For simplicity, this document focuses on SF 2584.

[2] Stillwater-AFPM NM and MN LCFS Assessment, September 14, 2021.

[3] This bill was incorporated into the House version of the biennial authorization bill for the Minnesota Department of Commerce but removed when reconciled with the Senate version of the Department of Commerce bill which was ultimately enacted.

[4] 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.

[5] 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.

[6] CA, OR, and WA 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. California is currently considering the addition of deficit generation for jet fuel used in intrastate flights as part of the 2023 amendment package currently in development.

[7] This consists of 1,976,525 automobiles, and 3,165,856 trucks.

[8] In 3Q2023, RNG in California generated 1.21 million credits, electricity 1.67 million credits, and hydrogen 0.02 million credits for a total of 2.89 million credits out of total credit generation of 6.94 million.

[9] Minnesota has a per-gallon mandate of 20% biodiesel from April 15th through September 30th each year. The minimum standard is 5% biodiesel for October through March and 10% biodiesel from April 1st through April 15th.

[10] Currently proposed amendments to the California LCFS, if adopted, will require a 90% CI reduction by 2045.

[11] This consists of 1,976,525 automobiles, and 3,165,856 trucks. 

[12] Advanced Clean Cars II Rule. This requires that 35% of all new car sales in California be ZEVs by 2026 and that this percentage increases to 100% of new car sales by 2035. 

[13] The California LCFS regulations include a price cap of $200/MT in 2016 dollars. As of June 2023, inflation (as measured by the U.S. Consumer Price Index) has resulted in the credit price rising to $253.53/MT. Using long-term inflation rates projected by the Federal Reserve Open Market Committee as of 1Q2023 (5.5% in 2024, 3.0% in 2025, and 2.5% in subsequent years), results in an expected price cap value of $311.70/MT in 2030 and $399.00 in 2040.

[14] Proposed LCFS program amendments would require a 30% CI reduction in 2030 and a 52.5% CI reduction in 2035.

[15] (100% – 75%) X 100.45 gCO2e/MJ = 25.11 gCO2e/MJ.

[16] Fuel suppliers operate in a competitive marketplace and face various conditions based on their location, configurations, access to feedstocks, and numerous other variables that may affect their ability to pass some of the cost increases on to consumers.

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