Matthew Blair

Sized the ethanol projects and timeline, and said plainly there is no intent to expand renewable diesel given policy uncertainty.

Direct, and three executives added to it, including the risk that the RIN goes unfeasible.

Randy confirmed multiple Jones Act waivers for products (renewables and conventional) from Gulf Coast to West Coast and Florida.

Eric Fisher explained ethanol is cheapest global octane with surging international demand. PTC booked at $0.10/gallon on 10 plants with potential additional $0.10-$0.20 pending guidance.

Eric confirmed ethanol plants are positioned for PTC capture from prevailing wage and qualified sales perspectives, awaiting final guidance. Credits work in 10-cent increments, so ethanol could receive 10 or 20 cents per gallon.

Randy confirmed displacement is a mix of incremental fuel oil cargoes, Latin American heavy, and Canadian heavy depending on location, with the overall push to maximize heavy crude processing system-wide.

Eric confirmed improvement driven by lower fat prices from industry rationalization, strong SAF premiums, and full PTC capture, but flagged PTC changes on foreign feedstocks in Jan 2026.

Gary argued pipeline tariffs are competitive with but not significantly cheaper than waterborne import parity, so California market pricing shouldn't change materially.

Greg noted Quebec turnaround impacted throughput but not capture, while strong commercial margins and Pembroke running well drove results.

Rich Walsh cited DOE analysis showing RFS doesn't disproportionately harm small refiners, predicting few SREs granted and significant legal challenges to any that are.

Greg noted seasonal butane removal hurts capture while lower maintenance impact on throughput means less capture distortion, making the net effect uncertain.

Eric noted Midwest governors' E15 push created supply chain complexity, and calculated the U.S. can only reach E12 with domestic ethanol, making nationwide E15 far off.

Eric clarified foreign UCO was always strategically directed to SAF for European markets, so 45Z exclusion doesn't change DGD's feedstock plans.

Gary clarified Quebec imports gasoline and only exports diesel seasonally to New York Harbor, with ability to redirect globally, so no throughput reduction expected.

Management deferred to market efficiency and declined to predict the RIN path or disclose hedging actions.

Rick confirmed Q1 sour guide at 50% vs 47% in Q4; system leaning into widening sour differentials as MPC's optionality allows rapid slate optimization.

Rick confirmed less Mexico exports but strong demand from Brazil and other LatAm more than offsets; strong Q4 exports and good Q1 start. CEO noted Maya is a very small part of sour basket.

CEO stopped short of discussing shutdown but confirmed no new capital; CFO acknowledged more unknowns than knowns on regulatory items, with clarity unlikely before 2026.

CFO clarified MPC includes crude differentials in blended crack indicators, so wider diffs drive margin but not capture; Rick attributed widening to TMX competition for ANS and stronger Bakken/Syncrude production.

CEO explained strategic goals between partners diverged; MPC remains largest ethanol blender with no commercial impact; portfolio optimization consistent with strategic priorities.

Rick cited 5-year low diesel inventories, strong over-the-road and ag demand, jet production pulling away from diesel, plus potential hurricane and cold winter catalysts.

Jim Wilkins noted CARB expected to issue revised LCFS package by end of May with OAL decision by end of June; effective date could be Q2 or pushed to 2026.

CFO declined to commit on Q2 RD profitability; focused on controllable factors including feedstock optimization, Martinez PTU utilization, and Neste partnership advantages.

Rick said the strategy is to maximize low-CI feedstocks for 45Z credit optimization, without committing to specific feedstock mix changes.

Rick highlighted robust demand from Latin America and Europe, with diesel steady but a significant uplift in gasoline export demand.

Rich framed Atlantic Basin capture on a first-half basis (~112% avg including the Humber turnaround) and said assets ran reliably; Brian noted backwardation easing into Q3.

Brian explained WCS widening to ~$18 driven by light sweet crudes pulled to Asia and Venezuelan barrels/refinery outages pressuring heavy grades. PSX sensitivity: $140 million additional earnings per dollar wider.

Mark said commissioning Q4 2026, ramping through first half 2027. Initially largely export-oriented. Majority of ethane sourced from PSX with connectivity to multiple supply sources.

Rich characterized L.A. impact as nonmaterial to both earnings and overall system market capture given 135K bpd within 2M bpd total operation. Cost to produce was very high and earnings were very low to negative.

Mark acknowledged attractiveness of recent SAF capacity valuation ($4.50/gallon). Everything on the table for Rodeo asset but must create value.

Rich explained two factors: Bayway storm-related power outage (plant back up) and L.A. refinery wind-down beginning in late Q3 ahead of Q4 cessation.

Brian confirmed seasonal uptick expected in Q2 M&S. Kevin declined to break out EBITDA by wholesale vs retail channel; bulk of M&S is wholesale model.

Rich explained L.A. closure accounts for ~50% of the gap from $5.90 to $5.50. Balance comes from continuous improvement and reliability programs. Target achievable by 2026.

Brian confirmed SAF production resumed in January and February. Using linear program to optimize product mix between RD and SAF based on market netback.

Neppl said no waiver signals are known and redirected to SREs and the Set 3 biofuel policy as the nearer-term policy watch items.

Neppl prioritized working capital and the leverage ratio, reaffirmed the 50% discretionary cash flow framework, and called buyback timing hard to predict.

Neppl clarified RMI credit was adjusted at Viterra close (not this quarter) because Viterra had higher RMI credit with rating agencies. Blended rate went up for combined company.

Neppl listed Q2 headwinds: higher interest, higher tax rate (Q1 was unusually low from discrete items), more challenging tropicals (CBE/cocoa/tariff uncertainty), and higher corporate expense from performance-based incentives.

Heckman cited demand development, grain merchandising improvement, synergy execution (cost and commercial). Neppl explained soy/soft use forward curves (more predictable) while merchandising has no curves and depends on environment.

Neppl said only modest pull so far with oil stocks still building. But model shows demand could turn very quickly from surplus to tight market once RVO finalized. Starting to see anticipation but not near expected levels.

Carter expects U.S. ethane pricing to stay low on ample supply, a feedstock-cost advantage for Dow's assets in advantaged regions (over 60%).

Fitterling said AI/power demand drives gas production which benefits NGLs. 8% frac capacity growth by end 2026. Current ethane outlook 20-23 cents with 25 cent frac spread (normal range). Recent spike was weather-related freeze-offs.

Carter said Chinese imports (~20% of US MDI market) dissipating quickly after antidumping ruling; seeing volume not yet pricing benefit. Housing needs sub-6% rates for recovery.

Fitterling said not meant for CapEx redeployment; about maintaining flexibility. Stock at buyback-attractive levels but no capacity to do so with old dividend. Tate noted no debt maturities before 2027.

Fitterling acknowledged pressures on capital structure, said $6B supports dividend but will monitor as macro evolves. Needs tariff clarity before end of 90-day pause.

Luciano confirmed starch demand is stabilizing, helped by cardboard and packaging (industrial and home delivery), a counterbalance to liquid sweetener softness.

Luciano attributed the inverted curve to strong near-term demand for soybean oil and meal with soybeans trading flat, while second-half uncertainty persists around trade deals, crop weather, energy prices, and consumer impact.

CEO highlighted Vietnam and Japan as emerging markets queuing for ethanol blending. Noted U.S. ethanol is cost-competitive at ~$1.60 vs comparable oxygenates at ~$2.90. On E15, said there are no technical barriers but the industry needs to align on infrastructure. ADM's carbon capture capability could provide low-carbon-intensity advantages for international markets.