Theresa Chen

Swords cited strong export demand and early talks with offtakers for capacity beyond current contracts.

Sheridan confirmed increased dock utilization, room for brownfield expansion, and crude dock recontracting at favorable rates. LPG dock commercialization has accelerated, especially post-Middle East conflict.

Sheridan described producers leaning into production via faster well turnarounds, more completion crews, and DUC drawdowns. Some are looking at additional rigs, especially as the back-end curve strengthens.

Sheridan confirmed the splitter is highly utilized with strong spreads and has been recontracted for term, providing long-duration earnings visibility.

Sheridan confirmed all $150M of 2026 synergies are identified, planned, and underway, coming from same buckets shown on page 9 of the investor deck.

Sheridan confirmed Denver Phase 1 fully contracted with take-or-pay, Phase 2 commercialization being pursued actively. Sunbelt had open season interest but not enough to FID; competing project also lacks sufficient commitments.

Pierce noted enough rigs running to hold crude flat, with rising GORs (Bakken at 3.1) driving continued gas/NGL growth even in flat production environment.

Sheridan expressed satisfaction with contracting progress but declined specifics for competitive reasons, noting strong supply position continues to attract customers.

Sheridan gave detailed basin-by-basin update: Bakken steady, Oklahoma strong in Cherokee formation, Permian ramping with 1.6 Bcf in July and FID on new plant.

Sheridan defended LPG dock economics citing premier location outside Houston Ship Channel, rates in line with estimated economics, and strong customer interest.

Sheridan confirmed substantial synergies underway, with key Easton/Gulf Coast connections completing second half 2025 and majority of synergies within ONEOK's control.

Walt noted ~$1B of annual capital can flex naturally with producer activity, plus ability to pause larger projects as demonstrated in 2016 and 2020.

Walt explained 2026 growth driven by completion of synergy capital projects connecting Easton assets and other projects completing in late 2025/early 2026.

Sheridan emphasized premier location (2 hours to open water), brownfield economics, connectivity to NGL storage, and expandability beyond 400,000 bpd.

Direct, with the mechanism spelled out: hydroskimming rather than cracking margins in Northwest Europe now set crack spreads.

Direct: quantified the ethanol production tax credit path and explained why D4 values should stay above fat prices into 2027.

Eric Fisher noted DGD mark-to-market headwind on forward feedstock positions if commodities continue rising, but RVO is strong tailwind with better 2026 outlook.

Homer explained proactive risk management including LIFO inventory positioning, reduced derivative exposure, and elevated cash position at $4-5B high end.

Gary detailed Q4 inventory builds driven by high utilization not weak demand, noted 500K bpd demand growth vs 400K bpd capacity additions for 2026, and flagged execution risk on consultant assumptions about Russian capacity and new startups.

Randy noted historical Venezuelan heavy runs up to 240K bpd, with the new Port Arthur coker substantially increasing processing capability beyond that, plus multiple factors (OPEC increases, Kirkuk, Canada, higher freight) widening differentials.

Gary noted Valero prefers waterborne flexibility over pipeline commitments due to West Coast margin volatility, and already has connectivity through McKee to El Paso and Phoenix.

Gary reported gasoline flat/slightly down, jet up ~4% per DOE, diesel up 8% in Valero system (broader market ~2%), with transatlantic gasoline arb closed through Q1.

Gary provided detailed demand breakdown showing gasoline flat, diesel up 3%, diesel inventories at historic lows with open export arbs, calling fundamentals very supportive.

Gary outlined Q4 as the inflection point for wider differentials as OPEC barrels, post-summer fuel oil, Canadian recovery, and turnaround season all converge.

Eric explained that without the blender's tax credit, marginal BD/RD producers can't operate, and RINs need to rise 40-50 cents more to incentivize their return.

Gary confirmed permit was reinstated after Valero demonstrated full compliance, and noted the anti-illegal-fuel effort will positively impact their Mexico business.

Greg explained the $230M project increases light olefin production to fill spare alkylation capacity, adding 6,000-7,000 bpd of high-octane alkylate, meeting mid-cycle return hurdles.

Gary noted fundamental supports for heavy sour discounts (OPEC additions, Lyondell closure) but said tariff/sanctions rhetoric is dominating and muting market moves.

Sital touted Tennessee's existing four-pipe corridor and supply diversity as advantages but declined to comment directly on Boardwalk's Borealis project.

Confirmed Q1 lump sum recognition but did not quantify the amount. Noted tanks were backfilled on long-term basis with rates stepping up over time, largely offsetting lost earnings.

Dang detailed strategic rationale: long-term contracts, 90% utility/industrial customers, storage synergies, and expansion activity that will bring high single-digit multiple down over time.

Kim said too early to discuss specifics. Still need to complete open season and negotiate details with Phillips 66 partner. Costs and contribution structure not yet finalized.

Kim said Phase 1 on track for late Q1/early Q2. Sital said initial phase well contracted with volumes coming from KMI's own plants providing visibility. Phase 1 likely on the earlier side of the timeframe. Phase 2 discussions continue positively but will be monitored against macro conditions. Kim noted growing GORs in the Bakken as a positive.

Kim said competitor only serves Phoenix while Western Gateway accesses multiple markets: new pipeline from Borger to Phoenix, reversed West line enabling California and Las Vegas access. Gives Arizona independence from declining California refining. Open season ends December 19 with targeted 2029 in-service requiring various regulatory approvals.

Kim said $10B opportunity set is mostly natural gas supporting LNG, power, Mexico exports, and industrial growth. Projects span Arizona to Florida, mostly under $250M with a few over $1B. Opportunity set comparable to when backlog was at $3B with no diminishment. Includes power demand across Arizona, Texas, New Mexico, and Florida plus egress from Haynesville and potentially Marcellus/Utica.

Kim confirmed Arizona demand from utilities and potential data centers. Copper State could be $4-5 billion but is a competitive process complicated by constantly changing tariffs. Smaller brownfield projects also under consideration. Must meet return thresholds.

Kim cited three factors: existing asset footprint advantage, track record of building and delivering projects on time, and customer service practices including advance maintenance notification and minimizing customer impact.

Sital said no impact expected. End-market demand drives pipeline throughput regardless of which refineries supply it. Waterborne barrels from Washington State or Asia can replace closed California refinery output.

Sital said integration going well with north-of-river processing complementing existing footprint. Looking at capturing more of NGL value chain but declined specifics due to competitive dynamics.

Kim cited capital and commercial synergies with existing Bakken assets but declined to quantify them. Downstream synergies possible but not immediate. Processing north of the river opens new flexibility.

Kim confirmed returns are consistent with historical targets. Competitive wins on MSX and Trident demonstrate infrastructure advantage. Required returns adjust for project risk profile.

CCO gave specific differentials and expected WCS to widen ~$2/bbl into 4Q, a feedstock tailwind.

Rick confirmed resilient demand with no elasticity impacts yet. West Coast wholesale volumes actually increased as competitors exited. Strong jet demand across all regions.

Rick outlined delivered and FOB mix strategy targeting Asian, European, African markets. Will retain spot market exposure. CEO confirmed this is a growth platform beyond Frac 1 and 2.

Rick highlighted growing DOD demand in LA region and jet production upside at LAR but declined to quantify specific volume increases for competitive reasons.

CEO noted ~1M bpd Indian/Asian additions but mostly petchem-oriented, with historically slower ramp; demand growth of 1-1.2M bpd annually supports enhanced mid-cycle; 2026 may be back-end loaded.

Rick expects sour differentials to widen in Q1 on OPEC+/Canadian production; ASCI at 5-year weak; offshore production above 2M bpd first time since 2020; TMX demand waning from Far East.

Rick emphasized Salt Lake feedstock advantage with black and yellow wax crude; de minimis pipeline volumes won't affect their position; product clearing to Vegas and Arizona provides optionality.

CEO outlined 1M+ bpd closures vs ~900K-1M bpd additions (Dangote, Dos Bocas) with 1-1.2M bpd demand growth; extremely constructive outlook once additions are absorbed.

CEO pointed to growing MPLX distributions enabling capital returns, portfolio optimization (Andersons sale as example), and LPG export marketing as near-term growth avenues.

Rick argued imports create volatility not sustainability given 40+ day transit time and unpredictable pricing; MPC's cost advantage beats import economics consistently.

CEO referenced Summit/Utica acquisition as evidence of dry gas interest but emphasized current priorities are Permian-focused; growth must meet mid-teens returns threshold.

Clear answer: MPC markets only MPLX's 50% share; ONEOK markets its own 200,000 bpd allocation independently.

Rick declined specific volume numbers but emphasized diversified go-to-market strategy (term/spot, FOB/delivered) and bullish outlook driven by Chinese PDH and global demand.

Tyler Cott said interest remains very strong, with some countries historically dependent on the Middle East now looking to shift long-term supply sourcing to the U.S.

Tyler gave commissioning timeline (May completion) but deferred on quantifying spot earnings uplift, noting they need to get through commissioning first.

Tyler Cott provided specific contract percentages and durations: 90% contracted, LPG through end of decade, ethane 10-20 years, 10% available for spot.

Tyler Cott detailed NRT ethane ramp through Q2 reaching full utilization, then second flex train starting propane shifting to mostly ethane by end of next year.

Randy outlined 2-3 year CapEx at $2-$2.5B with potential for $2.6-$2.7B. Buybacks will have both programmatic and opportunistic components.

Justin highlighted unique Salt Lake corridor positioning and broader benefit from Mid-Continent premium pricing across both TW and TE systems.

Chris noted PDH rates improved but still below expectations. Octane margins returned to historic levels from record highs. July margins improving with driving season.

Tug said Enterprise was largely unscathed due to diverse international exposure but the BIS action caused a non-Chinese company to choose naphtha over U.S. ethane.

Chris D'Anna confirmed both PDHs running, PDH-1 above nameplate. Renegotiated RGP purchase to fixed fee. Octane spreads 75% hedged for the year.

Chris D'Anna acknowledged global oversupply headwinds. Jim highlighted new Southeast Asian ethane contracts and potential European cracker closures.

Brent Secrest highlighted EPD's brownfield capital advantage at less than one-third of greenfield costs. Jim pledged to defend the LPG export franchise.

Brian listed tailwinds (Russia/Mideast outages, low inventories, disciplined Chinese exports); Kevin guided Q3 capture to the historical ~95%.

Mark declined to provide specific CapEx or build multiple, citing need to finalize scope and partner details. Said information would be available shortly.

Mark highlighted record DJ Basin volumes, recently restarted Powder River NGL pipeline for early Bakken barrels, and noted capacity expansion opportunities to fill downstream pipes from the Rockies.

Don sees no material change in ethane rejection or recovery with new gas pipelines. CPChem Golden Triangle coming online in 2027 adds significant ethane demand. Ethane pricing expected to balance with gas prices to maintain recovery economics.

Brian compared PADD 5 to PADD 1 import market model. About half of volume for Phoenix, rest for California. Mark noted OneOk has different source (Gulf Coast vs Mid-Con). Constructive open season conversations.

Don said 50-50 partnership with KMI. CapEx not disclosed as route and connection costs still being finalized. Kevin noted capital spend in 2027-2029 timeframe, no near-term impact.

Brian noted Freeport is mostly termed up with no cancellations. Mark added China has few alternatives for ethane; rational tariff discussions may be occurring.

Don explained Iron Mesa located near Goldsmith, serving Midland and Delaware Basins. Sub-5x build multiple. With Dos Picos plants, adds ~800K bpd gas processing, producing 100K+ bpd NGLs.

Mark said FTC isn't the primary filter; value creation and strategic fit drive M&A decisions. Don emphasized focus on organic growth first.

Kevin laid out $10B mid-cycle cash generation, $5B to shareholders, $2B CapEx, leaving $3B+ for debt reduction, bolt-ons, or buybacks.