John Mackay

John Mackay asked for more specific details on what is driving the current tightness in the market, particularly why it has become so tight so quickly. He also questioned the trajectory of gross margins, noting the strong Q4 performance against a flatter 2026 guidance, and asked about any conservatism or impact from AI-driven cost savings.

Answer

President and CEO Mickey McKee explained that the tightness is largely driven by a 'power discussion,' where new Permian processing plants, lacking grid access, are converting traditional electric motor-driven compression units to large natural gas-driven engines, creating unexpected demand. EVP and CFO John Griggs addressed gross margins, attributing Q4's strength to a 'clean quarter' with fewer cost gremlins. He noted some conservatism in the 2026 guide, but expects continued benefits from strong pricing and investments in operational technology and training.

John Mackay asked for more specific details on the drivers behind the rapid tightening of the compression market and sought clarification on the 2026 gross margin guidance trajectory.

Answer

Mickey McKee, President and CEO, attributed market tightness primarily to limited grid power access in the Permian, forcing processing plants to use large natural gas-driven engines instead of electric motors for internal compression, creating unexpected demand. John Griggs, EVP and CFO, explained that Q4's strong gross margin was due to a 'clean quarter' with fewer cost issues. He noted that the 2026 guidance includes some conservatism, but expects continued strong pricing and returns from technology and training investments to positively impact cost of goods sold.

John Mackay from Goldman Sachs asked how opportunistic acquisitions of operating horsepower fit within the company's growth targets and what factors determine the pace of the share repurchase program.

Answer

President & CEO Mickey McKee clarified that these opportunistic acquisitions are part of their growth strategy but are not expected to be large, transformative deals. He further explained that the share buyback cadence is primarily dictated by the share price, with the company becoming more active during periods of weakness while aiming to remain near its 3.5x leverage target.

John Mackay from Goldman Sachs questioned the macroeconomic assumptions behind the company's upper single-digit growth outlook, particularly in a flat oil price scenario. He also asked about the strategy for share buybacks and how it is balanced with achieving leverage targets.

Answer

CEO Mickey McKee expressed confidence in the growth outlook even with mid-$50 oil, citing continued natural gas production growth in the Permian. CFO John Griggs explained that the 3.5x leverage target is a primary focus, with share repurchases being used opportunistically to capitalize on attractive stock prices and to support the market during anticipated sales by major shareholder EQT.

John Mackay requested an on-the-ground perspective on gas-to-oil ratios (GORs) in the Permian and asked for more detail on the one-third of the 2025 CapEx budget allocated to non-unit growth spending.

Answer

CEO Mickey McKee confirmed they are seeing rising GORs in line with macro data, which drives sustained compression demand. CFO John Griggs detailed that the non-unit CapEx is front-loaded for 2025 and covers an ERP implementation, final CSI fleet upgrades, and strategic investments in technology and training, with a lower run-rate expected in the second half of the year.

John Mackay asked about cost trends for new compression units, the ability to pass on higher costs, and the primary drivers for customer adoption of electric motor units.

Answer

CEO Mickey McKee stated that new unit costs continue to see mid-single-digit inflation, which Kodiak has successfully passed on to customers to maintain target returns. He clarified that the adoption of electric motor units is '100% exclusively' driven by customer access to reliable power. He also noted that while Kodiak might evaluate opportunities in the power value chain, it would require considerable study.

John Mackay inquired about the price needed to underwrite the strong growth rate for China through 2030, specifically the general framework for the magnitude of gas switching from coal. He also asked for Cheniere's latest thoughts on dividend growth over time, particularly with the $30 per share DCF target, and its interaction with buybacks.

Answer

EVP and Chief Commercial Officer Anatol Feygin estimated a delivered price of $8-$9 for China, highlighting its fragmented market and capacity to consume substantial volumes at the right price, expecting a strong rebound in demand. CFO Zach Davis reiterated the commitment to 10% annual dividend growth through the decade, aiming for over 20% payout ratio. He emphasized the flexibility of their shareholder return policy, which includes significant buybacks, allowing for self-funding growth and opportunistic share repurchases, enhancing financial flexibility.

John Mackay asked about the price needed to underwrite China's strong LNG demand growth through 2030 and Cheniere's latest thoughts on dividend growth and its interplay with share buybacks.

Answer

Anatol Feygin (EVP and Chief Commercial Officer) estimated China's growth would need a delivered price of $8-$9 per MMBtu, with a $60-$65 Brent backdrop, expecting China to 'come roaring back' at this level. Zach Davis (EVP and CFO) reiterated commitment to 10% annual dividend growth through the decade, aiming for over 20% payout ratio. He emphasized that Cheniere's flexible shareholder return policy, including significant buybacks, enhances financial flexibility for growth and opportunistic repurchases.

John Mackay from Goldman Sachs inquired about the amount of incremental cash flow from recent tax law changes and its allocation. He also asked what market factors could drive SPA prices higher to support expansion beyond the initial next phases.

Answer

EVP & CFO Zach Davis detailed that 100% bonus depreciation and the foreign export deduction will significantly lower the cash tax rate, adding ~$200M to DCF in 2025 and providing more cash for the overall capital allocation plan. EVP & CCO Anatol Feygin suggested that SPA prices could firm up as other, less-certain projects fail to reach FID and as the EPC market tightens, but reiterated Cheniere's focus is on the CapEx-to-EBITDA ratio, not absolute price levels.

John Mackay asked if U.S. export utilization is expected to fall as new capacity comes online and inquired about the drivers behind weak Asian LNG imports so far this year.

Answer

EVP and CCO Anatol Feygin argued that the market is more sophisticated and has significantly more regasification capacity than in past supply cycles, making it a question of the clearing price for price-elastic demand rather than a supply shut-in. He attributed weak Asian imports overwhelmingly to China, driven by weather, strong domestic production, and increased Russian pipeline gas.

John Mackay asked for an update on the potential timing for a Final Investment Decision (FID) on the Sabine Pass expansion, noting previous discussion of 2026 and the new phased approach.

Answer

EVP and CFO Zach Davis clarified that an FID is more likely in 2027, or late 2026 at the earliest. He explained the current priority is to use the constructive permitting window to secure permits for the full 90+ MTPA potential across both sites. Achieving this long-term optionality is more critical than rushing an FID, though he noted spending on long-lead time items for the project could begin next year.

John Mackay questioned why Cheniere has maintained its long-term $2.00-$2.50/MMBtu marketing margin guidance given rising industry-wide EPC costs.

Answer

EVP and CFO Zach Davis clarified the range is for run-rate guidance transparency, contrasting with much higher current netbacks. EVP and CCO Anatol Feygin added that while costs are at the high end of the range, the competitive landscape for U.S. Gulf Coast projects has not yet justified breaching it. He stressed that Cheniere's brownfield advantages allow it to achieve strong returns even within this existing framework.

John Mackay, VP of Equity Research at Goldman Sachs, inquired about the structural feasibility of achieving $1,000+ Surface Use Economic Efficiency (SUEE) for the 2024 and 2025 acquired acreage, and the long-term SUEE target for the overall platform, excluding large data center projects.

Answer

Scott McNeely, CFO of LandBridge, confirmed that $1,000+ SUEE is "very, not just achievable, but actionable in the near term" for the 2024 and 2025 acreage, citing the similar trajectory of legacy acreage which grew from below $465 to $1,159 in four years. He reiterated the medium to long-term target of $2,500-$3,500 per acre over a 7-10 year period for the total portfolio.

John Mackay asked about the long-term potential for the surface use economic efficiency (SUEE) metric for the 2024 and 2025 vintage acreage, specifically if reaching $1,000 per acre is structurally possible, and what the overall platform's SUEE could look like over a medium to long-term timeframe, excluding large data center projects.

Answer

CFO Scott McNeely affirmed that $1,000+ per acre SUEE is not only achievable but actionable in the near term for the 2024 and 2025 acreage, drawing parallels to the legacy acreage's growth from below $465 to $1,159 over four years. He reiterated the medium to long-term target of $2,500-$3,500 per acre over a 7-10 year period, driven by continued compounding commercial activity, and invited investors to the upcoming Investor Day for more details on achieving this.

John Mackay of Goldman Sachs inquired about the current utilization of LandBridge's pore space, asking how much is already committed, and about the company's strategy for land acquisitions. He also asked if the strong quarterly easement revenue was due to one-off payments or represented a new sustainable run rate.

Answer

CEO Jason Long responded that the company has identified over 5 million barrels per day of potential pore space capacity and continues to actively seek additional land acquisitions. CFO Scott McNeely clarified that while the strong easement revenue included a mix of renewals and upfront payments, it should not be seen as a new run rate. He emphasized that while there will be quarterly lumpiness, the overall revenue trend is one of compounding growth over time.

John Mackay inquired about the recovery of curtailed volumes, specific expectations for 2026, and the trajectory of Kings Landing 2, including its factor into Acid Gas Injection (AGI) capacity.

Answer

Trevor Howard, SVP and CFO, stated that 50 million cubic feet per day of the 170 million cubic feet per day curtailed in Q4 2025 have come back online due to contract amendments. He projected an average of 100 million cubic feet per day of curtailments for 2026, primarily from Apache's Alpine High area. Jamie Welch, President and CEO, confirmed progress on Kings Landing 2 commercial negotiations, with an announcement expected in 2026, and capital already factored into the budget. He detailed the AGI capacity ramp-up to over 31 million cubic feet per day.

John Mackay inquired about Kinetik's ex-curtailment volume guidance, the return of previously curtailed volumes, and specific expectations for 2026. He also asked for an update on Kings Landing 2 (KL2) commercial negotiations and its impact on Acid Gas Injection (AGI) capacity.

Answer

Trevor Howard, Senior Vice President and Chief Financial Officer, explained that 170 MMcf/d of curtailments occurred in Q4 2025, with 50 MMcf/d brought back online due to contract amendments, and 100 MMcf/d assumed for 2026. He noted high single-digit system growth, with Delaware North up 35% year-over-year and Delaware South up 3% (10% normalized). Jamie Welch, President and Chief Executive Officer, stated that KL2 negotiations are progressing, with an FID anticipated in 2026, and detailed the AGI capacity ramp-up to over 31 MMcf/d.

John Mackay of Goldman Sachs inquired about Kinetik's macro view on producer activity, the signals that would trigger a reduction in CapEx, and how the company's fee-based revenue percentage is expected to trend beyond 2025.

Answer

CEO Jamie Welch described the environment as a 'yellow light,' proceeding with caution, and noted any slowdown would be customer-specific. CFO Trevor Howard added they remain responsive to customer needs. Regarding revenue mix, Welch stated that despite some puts and takes, investors should expect the fixed-fee composition to remain in the 'mid-80s' percentage range going forward.

John Mackay from Goldman Sachs requested an update on the sour gas opportunity and its competitive landscape, and asked about the drivers behind margin improvements from compression.

Answer

CEO Jamie Welch stated that significant sour gas opportunities remain a key differentiator in the Northern Delaware, and Kinetik is well-positioned with existing and planned capacity to capitalize on them. Regarding compression, Welch explained the margin improvement is a combination of self-help, by redeploying units inherited from Alpine High, and a strategic response to rising third-party costs for both new units and lease renewals.

John Mackay from Goldman Sachs & Co. inquired about the specifics of Golar LNG's strategic review process, including its timing, decision-making factors, and whether a potential sale of the company is being considered. He also asked if the current focus is on share buybacks and when the company would prioritize commercializing the next FLNG vessel over capital reallocation.

Answer

Chairman of the Board, Tor Olav Trøim, declined to provide further details on the strategic review or potential sale, emphasizing the need for confidentiality. CEO Karl Fredrik Staubo clarified that Golar LNG remains committed to FLNG projects but will not proceed with speculative vessel orders due to diverse design requirements and cash flow considerations. Tor Olav Trøim added that the strategic discussions do not impact day-to-day operations and that delaying future vessel investments aligns with building a stronger balance sheet for multi-billion dollar projects when significant cash flow is generated from existing operations in 2028.

John Mackay asked for more details on the strategic review process, including timing, decision factors, and whether a potential sale of the company is an option. He also inquired if the current focus should be on further share buybacks versus investing in the base business or commercializing the next vessel.

Answer

Chairman Tor Olav Trøim declined to provide further comments on the strategic process details, emphasizing the need to keep such discussions confidential. CEO Karl Fredrik Staubo clarified that Golar's commitment to accretive FLNG growth remains unchanged, but the decision to delay speculative capital commitment for the fourth vessel is due to varying design requirements and a desire to align investment with future cash flow. Mr. Trøim added that the strategic review does not impact day-to-day business and that pushing back capital needs for future vessels allows for a stronger balance sheet when significant cash flow from existing operations materializes.

John Mackay asked for a breakdown of the 2026 CapEx guidance, focusing on larger projects over the next two years and the all-in return profiles for that capital. He also inquired about capturing more Permian GNP volumes, potential inorganic opportunities in the Permian, and how synergy capture experience informs future considerations.

Answer

CFO Walt Hulse listed key 2026 projects (Denver pipeline, Shadowfax plant, Medford phase one) and early 2027 projects, noting larger projects are mostly complete, with future spending on routine growth and maintenance. Chief Commercial Officer Sheridan Swords stated 2026 Permian GNP growth is contract-based, with opportunities from RFPs and customer relationships. CEO Pierce Norton emphasized focus on organic execution and disciplined M&A for strategic fit.

John Mackay asked for a breakdown of the 2026 CapEx guidance, distinguishing between larger projects and routine growth/maintenance, and the all-in return profiles for this capital. He also inquired about capturing more Permian GNP volumes and potential inorganic opportunities in the Permian, considering synergy capture experience.

Answer

CFO Walt Hulse listed key 2026 projects including the Denver pipeline expansion, Shadowfax plant, and Phase 1 of Medford, noting that larger projects are mostly completed. He outlined annual spending of approximately $600 million for maintenance and $1 billion for routine growth, with the commercial team seeking $400-$500 million in other larger projects. The Texas City Export Terminal JV will wrap up by 2028. CCO Sheridan Swords discussed Permian GNP growth from existing contracts and RFPs, leveraging customer relationships. CEO Pierce Norton stated the focus is on executing the 2026 plan, with no glaring holes in the portfolio, and M&A decisions will be intentional and disciplined, fitting strategic objectives.

John Mackay asked about the crude side volumes, noting year-to-date softness compared to the full-year guide, and how this segment is expected to grow into 2026 given a flat rig environment. John Mackay also inquired about framing the overall size of ONEOK's blending business on an annual run-rate basis in a mid-cycle environment, following the Easton integration and upcoming Conway tie-in.

Answer

Sheridan Swords, Executive Vice President and Chief Commercial Officer, clarified that the volume decrease was primarily in the high-volume, low-margin business, while the core crude gathering business remains within expectations and is anticipated to grow. He explained that while blending margins fluctuate with spreads, synergies have increased blending volume by 15%, positioning ONEOK for upside when prices and spreads normalize. He noted that blending remains a small portion (10%) of the overall business.

John Mackay asked about the dynamics of ONEOK's crude oil volumes, noting year-to-date softness compared to the full-year guide, and how this segment is expected to grow into 2026 in a flat rig environment. Mackay also requested an estimate of the overall size of the blending business on an annual run rate basis, considering the Easton integration and upcoming Conway tie-in.

Answer

Sheridan Swords, Executive Vice President and Chief Commercial Officer, explained that the slight decrease in crude volumes was primarily in the high-volume, low-margin business, while the core gathering business from leases and batteries is performing as expected and is a key growth driver. Swords noted that the blending business fluctuates with spreads but synergies have increased physical blending volumes by 15% year-to-date, positioning for upside when spreads normalize, though it remains a small portion (10%) of the overall business.

John Mackay asked if Targa is still achieving historical margin levels or about the trajectory of margin per M, implying continued market share gains. He also sought Targa's medium and longer-term view on Waha natural gas prices.

Answer

Jen Kneale, President, affirmed that Targa expects to maintain consistent returns, leveraging its strong producer contracts, large sour system in the Delaware, and overall Permian footprint for economic step-outs, emphasizing that current execution does not involve taking lower returns. Bobby Muraro, Chief Commercial Officer, stated that while new pipelines will improve egress, Waha prices will likely remain volatile, with a pattern of pipes filling up, basis getting rough, and new pipes coming online, expecting pipes to fill up faster than anticipated but acknowledging a ramp-up period.

John Mackay inquired about Targa's ability to continue taking market share in the Permian basin, the historical level of margins, and the trajectory of margin per M. He also sought Targa's medium and longer-term view on Waha natural gas prices, specifically whether current pipeline projects are expected to fill up as they come online.

Answer

President Jen Kneale affirmed Targa's expectation to maintain consistent returns, citing strong producer relationships, operational execution, and competitive advantages like the largest sour system and Permian footprint. Chief Commercial Officer Bobby Muraro described the Waha price environment as a 'bumpy ride' with new pipes coming online, expecting them to fill up over time, potentially faster than anticipated, but acknowledging a ramp-up period.

John Mackay asked about Permian activity levels, specifically how the ramp-up of Midland versus Delaware basins is progressing and if previous views have shifted. He also inquired about gas-to-oil ratio (GOR) swings across different Permian regions and the expected progression of GORs.

Answer

Matt Meloy, CEO, stated that growth across the Permian footprint is in line with expectations, with slightly stronger growth recently observed in the Delaware. He anticipates strong growth in both basins, with plants expected to be highly utilized. Jen Kneale, President, confirmed that Targa is not seeing broad or significant GOR swings, but rather a continuing and strengthening broad theme of increasing GORs across the footprint.

John Mackay inquired about Targa Resources Corporation's Permian activity levels, specifically asking if the expected ramp-up dynamics between the Midland and Delaware basins had shifted. He also sought broader comments on observed swings in gas-to-oil ratios (GORs) across the basin and their anticipated progression.

Answer

CEO Matt Meloy noted strong growth across the Permian footprint, with slightly stronger growth rates observed in the Delaware Basin recently, but both Midland and Delaware are expected to contribute significantly. President Jen Kneale stated that Targa is not seeing broad or big swings in GORs across the footprint, but rather a consistent broad theme of increasing GORs, which continues to strengthen and benefits Targa.

John Mackay asked about the timeline for potentially reducing CapEx to the previously mentioned $300 million level in a flat Permian environment and inquired about ramp-up expectations for new processing plants.

Answer

CEO Matt Meloy clarified that CapEx could step down to the ~$300 million level needed to maintain flat volumes only after the current slate of major downstream projects (frac trains 11/12, export expansion) are completed in 2026 and early 2027. Regarding plant ramps, he expects new Midland Basin plants to fill quickly due to system connectivity. In the Delaware Basin, which is becoming more interconnected, the ramp may be slightly more dependent on producer-specific growth, but the plants are still viewed as highly utilized and much-needed.

John Mackay asked for details on the growth potential and associated CapEx for Targa's sour gas business and questioned whether the 45Q tax credits could become a meaningful offset to future cash tax liabilities.

Answer

Executive Matt Meloy highlighted Targa's decades of experience and increased investment in sour gas infrastructure, like the new Bull Moose treater, as a key competitive advantage in the Delaware Basin. Executive Robert Muraro added that recent Delaware plants are all sour-capable. Regarding 45Q, Muraro described it as a 'nice to have' but marginal in the grand scheme, and Executive Jennifer Kneale confirmed it does not change their outlook of becoming a full cash taxpayer in 2027.

John Mackay asked for DT Midstream's perspective on the recent momentum in "behind the meter" demand, particularly in the context of utilities' focus on affordability, and how it compares to "front of meter" opportunities. He also questioned the potential for greenfield projects and/or incremental bolt-on M&A, similar to the ONEOK assets acquisition.

Answer

David Slater, Executive Chairman and CEO, noted that DT Midstream is seeing "energy island load" seeking long-term contracts on main pipelines. He highlighted that utilities are effectively integrating this demand within a regulatory construct, ensuring affordability for other customers and offering attractive features like grid connectivity and strong counterparty status to large load customers. Mr. Slater stated a preference for "in-the-footprint expansions" (brownfield) due to their ease, economics, and lower execution/regulatory risk compared to greenfield projects. He identified greenfield storage opportunities as a more likely near-term focus, driven by market price volatility signaling a need for more capacity.

John Mackay asked for DT Midstream's view on 'behind the meter' opportunities versus 'front of meter' with utilities, especially in the context of a broader focus on affordability. He also inquired about the potential for greenfield projects and/or incremental bolt-on M&A, similar to the ONEOK assets acquisition.

Answer

Executive Chairman and CEO David Slater noted that 'energy island load' is seeking pipeline connections, and DT Midstream is contracting with it on main lines. He highlighted utilities' success in managing this demand through regulatory constructs, which provides long-term durability. On greenfield opportunities, Mr. Slater stated a predominant focus on 'in-the-footprint expansions' due to their economic and lower-risk profile, but mentioned greenfield storage opportunities as a near-term possibility driven by market tightness.

John Mackay inquired about the traction for 'over the horizon' projects to transport incremental Appalachian gas to the Gulf Coast for Wave 3 LNG projects, current market readiness, and if DT Midstream is exploring providing power (beyond just gas pipeline) for behind-the-meter opportunities.

Answer

David Slater (President and CEO, DT Midstream) observed that large, long-haul projects for Gulf Coast LNG are not gaining significant traction yet, as current Midwest demand will likely prioritize cheaper Appalachian gas for local consumption. He reiterated DTM's strategic focus on its core pipeline business, stating they will not venture into power generation for behind-the-meter opportunities, but will provide pipeline infrastructure.

John Ross Mackay asked about the long-term prospect of transporting gas from the Upper Midwest to the Gulf Coast to anchor Wave 3 LNG projects, inquiring if DT Midstream is seeing engagement from potential shippers for such large-scale projects. He also followed up on behind-the-meter projects, asking if DT Midstream would consider providing power generation or if its role would remain strictly limited to providing gas and pipeline infrastructure.

Answer

President and CEO David Slater stated that while discussions for long-term Gulf demand are active, he doesn't sense market readiness for large-scale Upper Midwest to Gulf Coast projects yet, as near-term demand in the Midwest proper is likely to prioritize Appalachian gas. Regarding behind-the-meter projects, Slater affirmed that DT Midstream will not change its strategic focus to provide power generation, instead concentrating on its core business of expanding pipeline infrastructure (freeway or lateral) to such sites.

John Mackay from Goldman Sachs asked for clarification on the project backlog, questioning why the total remained at $2.3 billion despite $600 million in new FIDs, and how the remaining portion is risked. He also inquired about the expansion potential of the NEXUS pipeline and opportunities for Midwest utilities or producers to participate.

Answer

President & CEO David Slater explained that with 50% of the five-year backlog now FID'd just six months into the plan, the backlog is significantly de-risked. He noted the backlog figure will be formally updated annually. On NEXUS, Slater detailed that it was designed for compression expansions, allowing for digestible capacity additions of 100-200 MMcf/d per station, and can comfortably expand to 2.0-2.5 Bcf/d to serve growing regional demand.

John Mackay inquired about the behavior of private producers in the Haynesville, asking if they are pulling back activity in response to recent price declines after a strong Q1. He also asked for an update on the Utica gathering assets and the pace of development in the current softer liquids environment.

Answer

President and CEO David Slater responded that DTM is watching private producer activity closely but has not yet seen any signals of a pullback, suggesting they are disciplined about hedging when prices are attractive. Regarding the Utica, Slater clarified that DTM's assets serve the oil window, where economics are not NGL-dependent. He stated that development pace is consistent with guidance and that the asset represents a long-term growth opportunity that also feeds into DTM's NEXUS pipeline.

John Mackay questioned DTM's ability to gain market share in the Haynesville for both gathering and LEAP expansions and requested an update on the timeline and status of the company's Carbon Capture and Sequestration (CCS) project.

Answer

President and CEO David Slater expressed high confidence in winning a fair share of Haynesville growth due to the system's superior connectivity, planning to continue 'bite-sized' LEAP expansions. On CCS, he stated the state application is now complete and submitted, and the company is awaiting the final Class VI permit before reaching a Final Investment Decision (FID).

John Mackay asked about the natural gas macro environment, specifically when production might return to and exceed previous peaks. He also requested an update on the NEXUS pipeline's potential expansion capacity, cost, and timing.

Answer

David Slater, President and CEO, stated that while the timing is uncertain, he believes Haynesville production must recover to serve new LNG facilities coming online in 2025. For NEXUS, he detailed a two-step capacity increase: a completed hydraulic optimization adding ~100 million cubic feet/day with no capital, and a future capital-driven compression expansion in the 100-200 million cubic feet/day range.

John Mackay asked for details on the Desert Southwest (DSW) project's sizing decision timeline and key execution milestones for its late-decade online target. He also inquired about the various options being explored for the Lake Charles LNG terminal following the suspension of its development.

Answer

Co-CEO Mackie McCrea explained that the 42-inch pipe with a 48-inch option for DSW was secured in early December and the option exercised, with all pipe and compression ordered. He noted they are ahead of schedule on permits and right-of-way, targeting Q4 2029 for in-service. For Lake Charles LNG, Co-CEO Mackie McCrea stated they are exploring repurposing the terminal for NGLs, crude oil, or other commodities, leveraging its strategic location.

John Mackay asked about the timing of the sizing decision for the Desert Southwest Pipeline Project and the key milestones to watch for its completion by the end of the decade, including construction and permits. He also inquired about the different options being explored for Lake Charles LNG now that its development has been suspended.

Answer

Co-CEO Mackie McCrea explained that the 48-inch pipe and compression for Desert Southwest were ordered after exercising an option in December, and the project is ahead of schedule with extensive stakeholder engagement and right-of-way secured. Regarding Lake Charles LNG, McCrea stated that Energy Transfer is exploring various options for the terminal, including NGLs, crude oil, or other commodities, leveraging its prime location and infrastructure.

John Mackay asked how much of the 6 Bcf of new gas deals for power signed over the past year represents incremental growth, and whether the implied margin or fee from these deals is a reasonable run rate for future incremental power and data center transactions.

Answer

Dylan Bramhall (Group CFO) confirmed that all 6 Bcf represents incremental business from new demand sources currently under construction. He cautioned against universally projecting the weighted average fee, as it comprises a mix of contracts from Desert Southwest, Hugh Brinson, and other system demand growth.

John Mackay asked for clarification on the 6 Bcf per day of new gas deals signed over the past year for power and data centers. He wanted to know how much of this volume represents incremental growth and if the implied margin or fee from these deals is a reasonable run rate for future incremental power and data center contracts.

Answer

Dylan Bramhall (Group CFO) confirmed that the 6 Bcf per day of new deals is entirely incremental business, representing new demand sources currently under construction. He stated that while the math does yield a strong weighted average fee, it's important to note that this figure is composed of a mix of different contract types, including Desert Southwest, Hugh Brinson, and other demand growth along their systems, so it shouldn't be projected forward uniformly.

John Mackay of Goldman Sachs asked about the potential future mix of the business, questioning what percentage of total EBITDA could come from natural gas projects. He also asked if Energy Transfer would provide a forward-looking EBITDA growth rate target.

Answer

Group CFO Dylan Bramhall indicated that the Interstate and Intrastate gas segments are expected to grow the quickest as a percentage of the whole. Co-CEO Thomas Long noted the company has not planned to issue a specific growth rate target due to the "lumpy" nature of its growth, which includes M&A. Dylan Bramhall added that the 3-5% distribution growth target serves as a baseline for long-term DCF per unit growth.

John Mackay from Goldman Sachs Group, Inc. requested an update on the WTG acquisition, focusing on its performance, progress in gaining market share, and any NGL-related benefits. He also asked if the $160 million midstream benefit from Winter Storm Uri was included in the initial guidance.

Answer

Executive Mackie McCrea called the WTG acquisition 'great,' with strong reserves, while noting they are addressing some operational issues. Executive Dylan Bramhall added that volumes are ahead of the acquisition plan, and the deal is on track financially. Regarding guidance, Bramhall explained the $160 million Uri-related gain was not explicitly included but was offset by lower-than-expected Q1 gas price volatility.

John Mackay requested a breakdown of the new power and data center demand opportunities between interstate and intrastate systems and their potential timelines. He also asked for an update on the Permian NGL pipeline capacity versus plant flows post-WTG acquisition.

Answer

Executives Dylan Bramhall and Mackie McCrea acknowledged that Texas projects would likely move fastest due to permitting advantages, but noted that opportunities in Arizona and the Midwest could also advance quickly. Regarding Permian NGLs, Mackie McCrea stated that an expansion of the Lone Star NGL pipeline is underway and will be completed mid-next year, putting them in a "good shape" to handle contracted volumes for the next 2-3 years before further looping or expansions would be needed.

John MacKay inquired about Antero Midstream's longer-term growth trajectory beyond 2027, specifically how a consistent 3-rig, 2-completion crew program would impact throughput volumes and EBITDA growth after the M&A tailwinds subside. He also asked about the implications of Antero Resources' (AR) growth upside plans for Antero Midstream's EBITDA and capital requirements.

Answer

Michael Kennedy, CEO and President of Antero Midstream, stated that the 3-rig, 2-completion crew program is expected to provide continued growth past 2027, projecting approximately 200 million a day of throughput volume growth and mid- to high single-digit EBITDA growth, consistent with historical performance. Regarding AR's growth plans, Mr. Kennedy clarified that Antero Midstream anticipates no additional capital requirements beyond current budgets, as existing infrastructure, including trunk lines, pipelines, and water systems, is already in place, particularly for dry gas assets. He highlighted AR's strong positioning due to firm transport and access to diverse demand centers, including LNG to the Gulf Coast.

John Mackay asked how significantly LPG pricing would need to fall to trigger a production cut from Antero Resources that would impact Antero Midstream's volumes, and also inquired about other potential cost optimization or self-help projects.

Answer

Mike Kennedy, CFO of Antero Resources, stated definitively that even at extremely low prices, such as those seen during COVID, Antero Resources would not alter its 2-rig development program due to strong cash flow and low debt, ensuring volume stability for Antero Midstream. Brendan Krueger, CFO of Antero Midstream, added that while there are potential cost-saving opportunities like behind-the-meter power projects, these are still in the early stages of evaluation.

John Mackay questioned the key drivers behind management's confidence in achieving a sub-3x leverage ratio in Q4, asking if it was due more to lower CapEx or an implied EBITDA increase. He also asked if this achievement could trigger share buybacks in Q4 and sought clarity on what Q4's capital spending implies for the 2025 run rate.

Answer

Brendan Krueger, CFO of Antero Midstream, expressed high confidence in hitting the leverage target, attributing it to both a significant decline in Q4 capital spending and expected EBITDA growth. He confirmed the company would evaluate buybacks after reaching the 3x target. For 2025, he suggested that a capital budget in the middle of the previously stated $150 million to $200 million range is a safe assumption.

John Mackay from Goldman Sachs asked for a year-over-year bridge for the long-haul Permian volume guidance, focusing on the volume versus margin mix, and inquired about the recent storm impacts on volumes across the board and the current recovery status.

Answer

Jeremy Goebel, EVP and Chief Commercial Officer, attributed the long-haul Permian volume guidance to the full-year run rate of Cactus III, a significant uptick in contracted capacity on the basin pipeline system (explaining lower margins), and the full-year run rate of the BridgeTex pipeline. He stated that storm impacts, primarily affecting gas infrastructure and subsequently crude, resulted in an estimated loss of 10-12 million barrels of crude production over 7-10 days, but recovery has already occurred, and these impacts were considered in the guidance.

John Mackay asked for more detail on the increased CapEx, questioning if it signals higher producer activity or just commercial success, and requested a quantification of the EBITDA from the retained NGL assets.

Answer

EVP & COO Chris Chandler described the CapEx increase as a combination of new opportunities and synergy capture from recent bolt-ons. VP of Investor Relations Blake Fernandez added that the 2025 budget includes deferrals from the prior year. EVP & CCO Jeremy Goebel quantified the retained NGL assets as generating approximately $10 million to $15 million in annual EBITDA.

John Mackay asked for more detail on the implied Permian EBITDA for 2025, seeking to separate the Cactus I contract step-down impact from underlying growth. He also asked about the timing for an update on recontracting efforts.

Answer

Jeremy Goebel, an executive, did not provide a specific Permian EBITDA guide but noted some growth is from filling previously underutilized physical capacity. Al Swanson, EVP and CFO, directed him to the presentation slides for high-level context. Regarding recontracting, Goebel stated it will be a gradual, continuous process with no 'grand unveil,' as they will optimize uncontracted space with shorter-term deals until market conditions are more favorable.

John Mackay inquired if increasing producer efficiencies could lead to a continued decline in Plains' gathering CapEx per barrel and asked for an update on the strategy to redirect volumes from the Oryx JV onto Plains' long-haul pipes.

Answer

EVP & CCO Jeremy Goebel confirmed that capital efficiency is improving, noting that nearly 40% of new connections are 'behind pipe' on existing facilities. Regarding the Oryx JV, Goebel stated it has performed better than expected, providing shippers with more options. While basin growth has kept all pipes full, the integration provides a defensive advantage and has helped Plains win more business with those customers across the value chain.

John Mackay asked for a breakdown of the Q2 crude oil outperformance versus the back-half guide, and requested an update on the EBITDA generation and trend for crude assets outside the Permian.

Answer

Executive Jeremy Goebel attributed the Q2 outperformance to non-repeating factors like favorable storage economics and lower utility costs. For non-Permian assets, he highlighted outperformance from the Rockies system, driven by Uinta rail volumes and full pipelines, as well as strong performance from Canadian gathering assets and the integrated system into Cushing.

John Mackay asked about international customer demand trends for NGLs, comparing current demand to the previous year. He also sought clarification on any incremental headwinds expected for 2026 that might offset the ramp-up of new projects, given the strong 2027 growth outlook.

Answer

Tyler Kott, a Company Representative, noted that NGL demand has been resilient, with U.S. LPG finding new markets in India and Southeast Asia, and strong interest in long-term export capacity. Co-CEO Jim Teague and Co-CEO Randy Fowler clarified that many new assets (Frac 14, processing plants, ethane terminal, LPG exports) are already full or highly contracted, and no significant headwinds are expected from 2025 to 2026, aside from the minor octane enhancement business. Randy also reminded that Q4 and Q1 are seasonally stronger quarters.

John Mackay first asked about international NGL demand trends, seeking color on current conditions and how they compare to the previous year. He then followed up by asking about potential headwinds for 2026 compared to 2025 that might offset the ramp-up of new projects, clarifying previous comments on 2027 growth.

Answer

Company Representative Tyler Kott stated that international NGL demand has been resilient, with U.S. LPG finding new markets in India and Southeast Asia, and strong long-term interest in export capacity. Co-CEO Randy Fowler and Company Representative Zach Strait confirmed that new assets like Frac 14, processing plants, and ethane/LPG terminals are virtually full or well-contracted. Randy Fowler noted that while $40 crude would be a headwind, significant commodity-sensitive headwinds are not expected for 2026 compared to 2025, beyond the change already seen from 2024 to 2025.

John Mackay of Goldman Sachs sought clarification on the margin compression in LPG exports, asking if the repricing process is now largely complete, and also inquired about potential recontracting pressure for Permian NGL pipelines.

Answer

Co-CEO A.J. Teague and SVP Tug Hanley confirmed that with 85-90% of LPG export capacity contracted through the decade, the significant repricing is complete, and they will defend their full capacity. SVP Justin Kleiderer added that the NGL pipeline business has very little recontracting to work through and expects volumes to continue increasing with supply growth.

John Mackay of Goldman Sachs asked for an update on margin compression in LPG exports, specifically whether the repricing process is complete, and inquired about similar pressures in other parts of the portfolio like Permian NGL pipelines.

Answer

Co-CEO A.J. Teague and SVP Tug Hanley confirmed that with 85-90% of LPG capacity contracted long-term, they will remain full and offset margin pressure with volume. SVP Justin Kleiderer added that for Permian NGL pipelines, there is very little recontracting risk through the decade as they expect volumes to continue growing.

John Mackay followed up on NGL exports, asking if a broader macro slowdown was impacting Asian demand. He also questioned if the company's updated market forecast would alter its 2026 CapEx budget.

Answer

Co-CEO A. Teague and executive Tug Hanley confirmed no change in customer behavior at their docks, citing new contracts in Southeast Asia. Hanley added that any demand slowdown would be managed by price adjustments. Co-CEO W. Fowler clarified the 2026 CapEx budget of $2.0-$2.5 billion is mostly for completing existing projects, with only a small portion allocated for new, yet-to-be-sanctioned projects.

John Mackay inquired about the potential impact of energy tariffs, particularly from China, on the company's export business and asked for commentary on NGL pipeline volumes, margins, and the competitive environment.

Answer

Co-CEO Jim Teague expressed little concern over NGL tariffs, stating that China needs U.S. propane and ethane. Executive Justin Kleiderer explained that NGL pipeline volume growth is driven by purity movements and Y-grade growth, and that despite new competition, the company's platform is well-positioned for high utilization, especially with the new Bahia pipeline in service.

John Mackay followed up on the valuation topic, asking if an 'Up-C' corporate structure has been permanently ruled out. He also asked for clarification on the operational status and cash flow contribution of the two PDH facilities.

Answer

Co-CEO W. Fowler expressed skepticism about the Up-C structure, viewing it as adding complexity for little proven value. Co-CEO A. Teague confirmed both PDH plants are fully operational and running at or above full rates, with an expected aggregate cash flow contribution of around $200 million.

John Mackay asked about MPLX's confidence in achieving mid-teens return targets for its project backlog, particularly in the context of 2025 growth versus the overall mid-single-digit target, and inquired about contract protections. He also followed up on the commercialization of Northwind synergy projects, specifically Secretariat II, and the strategy for capturing additional volumes from that system.

Answer

Maryann Mannen (President and CEO) affirmed confidence in mid-teens returns and mid-single-digit growth, emphasizing strict capital discipline and specific projects like Bengal, Secretariat I, Bayrunner, Blackcomb, and Harmon Creek III contributing to EBITDA. She clarified that Secretariat II supports both new growth from the Northwind platform and legacy volumes. Gregory Floerke (EVP of Operations) provided details on the Titan II expansion and connecting lines to integrate the sour gas system, noting robust growth in both sour and sweet legacy portions, which led to upsizing Secretariat II.

John Mackay asked about MPLX's confidence in achieving mid-teens return targets for its project backlog, particularly in the context of 2025's growth versus the overall mid-single-digit target, and inquired about contract protections. He also followed up on the commercialization success of Northwind synergy projects, specifically Secretariat II, and asked if more volumes could be captured from that system.

Answer

President and CEO Maryann Mannen affirmed confidence in mid-teens returns and mid-single-digit growth, citing specific projects like BANGL, Secretariat I, Bayrunner, Blackcomb, and Harmon Creek III contributing to 2026 growth. EVP of Operations Gregory Floerke added details on the sour gas system acquisition (Northwind), its integration with legacy systems, and the upsizing of Secretariat II to support robust growth from both new and existing volumes.

John Mackay asked about MPLX's updated EBITDA growth outlook, specifically comparing the current level and duration of mid-single-digit growth targets to initial expectations at the beginning of the year, and also inquired about the power LOI with MPC, including conversion steps, opportunity set, and expected returns.

Answer

Maryann Mannen, President and CEO, MPLX, explained that 2025-2026 growth is expected to be stronger than 2024-2025, with a 7% EBITDA growth rate projected to continue into 2026, driven by projects like BANGL, Secretariat, Preakness II, sour gas investment (Titan), Eiger Pipeline, and Gulf Coast Fractionation/LPG Export. Regarding the power LOI, she noted it's an early-stage, low-to-no-cost transaction that creates in-basin demand for MPC and provides MPLX with lower-cost, reliable power for producer customers, with no significant CapEx required from MPLX.

John Mackay asked about MPLX's updated EBITDA growth outlook, specifically how the level and duration of future growth compare to initial expectations, considering recent projects and M&A. He also inquired about the power LOI with MPC, including steps for conversion, opportunity scope, and expected returns.

Answer

Maryann Mannen (President and CEO, MPLX) detailed that 2025-2026 growth is expected to be stronger than 2024-2025, supported by Bangle's incremental ownership, Secretariat's ramp-up, full rate of PREACMUS II, and the sour gas investment (TITAN) reaching full run rate by late 2026. She also mentioned Eiger Pipeline (2027) and the first frac/LPG Export Terminal (2028-2029). Regarding the power LOI, Mannen explained it's an early-stage opportunity with MPC, creating in-basin demand and providing low/no-cost reliable power to producer customers, with project realization beyond 2026.

John Mackay inquired about the ramp-up timeline for the Northwind acquisition through 2026 and the potential for downstream growth opportunities, asking if they were included in the valuation multiple. He also asked about the sustainability of the 12.5% distribution growth in the coming years.

Answer

President & CEO Maryann Mannen stated that the Northwind acquisition is expected to reach its run-rate EBITDA by the end of 2026, supporting the seven-times multiple for 2027. SVP David Heppner clarified that incremental downstream growth opportunities are not included in the base economics and represent future upside. Mannen also affirmed that the 12.5% distribution growth is durable for the next few years, supported by strong, visible cash flow growth from ongoing projects.

John Mackay inquired about the ramp-up timeline for the Northwind acquisition through 2026, its downstream growth potential, and whether that potential was included in the stated valuation multiple. He also asked about the long-term sustainability of the 12.5% distribution growth.

Answer

President and CEO Maryann Mannen stated that the Northwind acquisition is expected to reach its run-rate EBITDA by the end of 2026, supporting the seven-times multiple, which already includes incremental capital. SVP David Heppner clarified that further downstream opportunities are not in the base economics and represent upside. Mannen also affirmed that the 12.5% distribution growth is durable for the next few years, supported by strong cash flows from ongoing projects.

John Mackay of Goldman Sachs asked for an update on MPLX's business contract mix, including take-or-pay agreements, and inquired about the capital budget's sensitivity to a shifting macroeconomic environment, particularly for joint venture projects.

Answer

President and CEO Maryann Mannen emphasized the durability of MPLX's strategy, its key relationship with MPC, and the just-in-time nature of its projects. CFO Chris Hagedorn specified that about 90% of the crude and products logistics segment revenue comes from MPC with significant protection, while the Marcellus business has over 75% volume commitment protection. Regarding capital flexibility, Maryann Mannen confirmed the $1.7 billion growth plan for 2025 is largely on track for key projects like Secretariat and Harmon Creek III, but noted flexibility exists for longer-term projects. EVP and Chief Commercial Officer Gregory Floerke added that new plants are being built under contract, not on speculation.

John Mackay asked for the strategic rationale behind the new NGL value chain announcement, particularly the partnerships with ONEOK and MPC, and inquired about future incremental growth opportunities stemming from this expanded footprint.

Answer

President and CEO Maryann Mannen explained the project extends MPLX's wellhead-to-water strategy and complements its existing asset base, noting the ONEOK joint venture enhances the terminal's competitiveness. SVP David Heppner added that future growth could arise from greater interconnectivity with MPC's Gulf Coast refinery assets, petrochemical customers, and further collaborations with ONEOK.

John Mackay asked for the rationale behind increasing the distribution growth to 12.5% from 10% and inquired about the future pace. He also questioned if the Harmon Creek III project in the Marcellus signals a broader set of growth opportunities in the basin.

Answer

Maryann Mannen, President and CEO, attributed the distribution hike to the durability of cash flows and successful growth projects, stating that mid-single-digit EBITDA growth provides confidence for similar increases in the future. Gregory Floerke, an executive, added that the Harmon Creek III project is an example of just-in-time capacity expansion driven by strong producer demand, longer laterals, and high utilization in the Marcellus, their largest operating area, suggesting potential for further incremental projects.

John Mackay from Goldman Sachs inquired about the current impact of severe winter weather on Hess Midstream's operations, particularly regarding power outages and production recovery. He also sought clarification on the company's longer-term leverage target.

Answer

CEO Jonathan Stein explained that the current weather impact is primarily due to extreme cold, affecting the gas system, and anticipates seasonal volume increases post-winter. CFO Mike Chadwick emphasized the 95% MVC coverage for 2026, providing a floor for revenues despite weather impacts, and reiterated that while there's no specific long-term leverage target, the company expects to naturally delever below 3x by using free cash flow for debt repayment and shareholder returns.

John Mackay asked for clarification on Hess Midstream's longer-term leverage target, specifically if there's a new specific target or if it's a natural delevering process.

Answer

CFO Mike Chadwick stated there is no specific new leverage target. He explained that the company expects natural delevering below the 3x level over the next three years as EBITDA grows, the absolute level of debt is not increased, and a portion of free cash flow is used for debt repayment, alongside shareholder returns.

John Mackay from The Goldman Sachs Group, Inc. inquired about the strategic thinking behind the long-term 200 kboe/d Bakken production target and asked for an update on drilling inventory life given recent upstream efficiencies.

Answer

President & COO John Gatling explained the 200 kboe/d target optimizes the balance between drilling activity and midstream infrastructure utilization. He also noted that inventory life is viewed through lateral footage, not well count, and that longer laterals are improving economics and unlocking new rock. CEO Jonathan Stein reinforced the continuity of the integrated upstream-midstream partnership with Chevron.

John Mackay from Goldman Sachs asked about the strategic thinking behind the long-term 200 kboe/d production target for the Hess footprint and requested the latest commentary on drilling inventory life given upstream efficiencies.

Answer

President & COO John Gatling detailed that the 200 kboe/d target was established to optimize drilling activity with midstream infrastructure for high utilization. He also noted that inventory life remains robust, as the shift to longer laterals improves economics and unlocks more rock. CEO Jonathan Stein added that the strong upstream-midstream partnership will continue with Chevron to optimize development.

John Mackay of Goldman Sachs asked if the increasing use of 4-mile laterals by Hess would alter the CapEx intensity for Hess Midstream. He also inquired about the state of gas egress in the basin, referencing a newly proposed residue pipeline.

Answer

John Gatling, President and COO, stated that longer laterals do not materially change CapEx intensity, as the ongoing capital for well tie-ins is expected to remain stable. Regarding gas egress, Gatling affirmed that HESM has sufficient takeaway capacity through existing agreements and that new projects like the Bison Express, where Hess is a shipper, add further flexibility.

John Mackay asked about Venture Global's strategy for funding a worst-case scenario in ongoing arbitrations, the accounting methodology for the $14-$15 million quarterly reserve, and the impact of the BP ruling on recent contract discussions and pricing.

Answer

CEO Michael Sabel detailed Venture Global's strong cash position, the spread-out nature of potential damages, and ample liquidity from current cash, future earnings, and unencumbered assets. CFO Jack Thayer clarified the $14-$15 million per quarter as a 'best estimate of award outcomes' for accounting purposes, not a cash charge. Michael Sabel affirmed the BP ruling had no impact on contracting, citing the significant volume of new 20-year SPAs as evidence of market trust and consistent pricing.

John Mackay of Goldman Sachs Group, Inc. inquired about the implications of the recent arbitration ruling on other contracts and future commercialization efforts, and also asked about the expected pace of contracting for CP2 Phase two and current pricing trends.

Answer

CEO Michael Sabel stated that all contracts are similar and based on standard industry forms, expressing confidence in similar outcomes for remaining cases. He noted the arbitration was an 'unnecessary distraction.' On contracting, Sabel confirmed they expect to execute additional 20-year contracts this year for CP2 Phase two and begin contracting for the Phase three brownfield expansion, with market prices in the mid-to-lower $2 per MMBtu range.

John Mackay of Goldman Sachs inquired about the implications of the recent arbitration ruling with Shell on other contracts and Venture Global's ability to commercialize future projects. He also asked about the expected pace of contracting for CP2 Phase 2 and current market pricing trends for long-term agreements.

Answer

CEO Michael Sabel stated that all contracts are similar, based on standard US project finance agreements, and expressed confidence in similar outcomes for remaining cases. He noted the arbitration was an "unnecessary distraction." Sabel confirmed they expect to execute more 20-year contracts this year for CP2 Phase 2 and potentially the Phase 3 brownfield expansion, with market prices in the mid-to-lower $2 per MMBtu range.

John Mackay asked about the pace of near-term cargo sales, the ability to capture market margins, and the outlook for signing additional 20-year sale and purchase agreements (SPAs).

Answer

Mike Sabel, CEO, stated that Venture Global is pleased with the strong market demand and is layering in sales of future cargoes rather than speculating on prices. He confirmed the company is in active negotiations for multiple 20-year contracts and expects to announce new deals in the coming quarters.

John Mackay asked for a breakdown of the 2025 EBITDA guidance, including assumptions on margins and the Plaquemines ramp-up, and inquired about market appetite for long-term contracts for CP2 and the Plaquemines expansion.

Answer

CEO Mike Sabel and CFO Jonathan Thayer explained that the guidance is based on a conservative view of the forward curve. Thayer provided a detailed calculation of the fixed liquefaction fee, while Sabel highlighted the unprecedented ramp-up at Plaquemines. Regarding contracts, management noted strong demand for a blended portfolio of 3- to 20-year tenors for CP2 and the Plaquemines expansion, aiming to leverage cost advantages to gain market share.

John Mackay of The Goldman Sachs Group, Inc. asked for an update on Williams' plan for its remaining upstream portfolio, specifically regarding the Wamsutter asset, following the recent Haynesville upstream sale.

Answer

President and CEO Chad Zamarin explained that Wamsutter is Williams' remaining upstream interest, a larger and more complex asset with very high margins due to its rich gas and liquids production, which captures significant value through Williams' midstream infrastructure (gathering, processing, NGL movement, fractionation, marketing). He stated that the strategy is to fully delineate and develop Wamsutter to its full potential, leveraging the value chain economics, and that this work will take some time. Mr. Zamarin noted that Wamsutter now represents only a couple of percentage points of total earnings, but its power in driving midstream business is most important.

John Mackay asked for clarification on Williams' plan for its remaining upstream portfolio, specifically Wamsutter, following the recent upstream asset sale.

Answer

President and CEO Chad Zamarin explained that Wamsutter is the company's remaining upstream interest, a larger and more complex asset with very high margins due to its rich gas and liquids basin, which allows Williams to capture significant margin through its midstream infrastructure (gathering, processing, NGLs, fractionation, marketing). The strategy is to fully delineate and develop Wamsutter to its full potential, leveraging the value chain economics from its midstream assets, a process that will take some time. He noted Wamsutter now represents only a couple of percentage points of total earnings but is crucial for driving power into the midstream business.

John Mackay of Goldman Sachs asked for details on the acceleration of the CECI project timeline. He also inquired about the rationale for refining the size of the Power Express project.

Answer

EVP & COO Larry Larsen explained that CECI's timeline was accelerated by receiving a faster environmental assessment, moving full in-service up a quarter, with potential for partial service in early 2027. President & CEO Chad Zamarin clarified that the Power Express project size was optimized to find the 'sweet spot' of capital efficiency and market demand, not just to maximize volume, and that further demand exists in that corridor.

John Mackay of Goldman Sachs asked for details on the potential to further accelerate the CECI project and the reasoning behind refining the size of the Power Express project.

Answer

EVP & COO Larry Larsen confirmed that a favorable environmental assessment for CECI allows for a one-quarter acceleration and potential for partial in-service in early 2027. President & CEO Chad Zamarin explained that the Power Express project size was optimized to find the 'sweet spot' of capital efficiency and market demand, and clarified this does not preclude future expansions along that corridor.

John Mackay asked for Williams' view on the momentum for permitting reform in Washington. He also questioned whether customers view the new behind-the-meter power projects as permanent solutions or as a temporary bridge to larger facilities.

Answer

CEO Alan Armstrong acknowledged encouraging signs from the administration and FERC but emphasized that permanent improvement requires legislative reform to address litigation risks. EVP Chad Zamarin stated that customers view these power projects as permanent solutions, supported by long-term, 15-year pipeline capacity contracts. Armstrong added they are an elegant alternative to expensive diesel backup generation.

John Mackay of Goldman Sachs & Co. asked for an update on potentially revising the long-term 5-7% growth target and inquired about the company's long-term strategy for its E&P assets after the recent JV buy-in.

Answer

CEO Alan Armstrong expressed confidence that consummating the direct data center projects would drive growth beyond the 5-7% target. However, he emphasized that the more fundamental driver is the underlying demand growth reflected in record peak days on Transco. EVP Chad Zamarin explained the E&P strategy is to optimize development to maximize value for Williams' downstream infrastructure. After optimizing the Wamsutter asset, the company will decide on long-term ownership, while it expects to move further toward divesting the Haynesville asset.

John Mackay asked what specific factors could enable Williams to exceed its 5-7% long-term growth target. He also inquired about the progress of conversations regarding data center opportunities and whether they involve behind-the-meter solutions.

Answer

CEO Alan Armstrong outlined several catalysts that could drive growth above the target range: the large number of high-return projects in the commercial pipeline, the potential for future bolt-on acquisitions not yet in the forecast, and the significant, low-capital earnings uplift from curtailed production coming back online. He confirmed that data center discussions are progressing well, involving a mix of serving on-grid power demand and direct behind-the-meter solutions, with opportunities becoming "much more concrete and positive."

John Mackay asked for more details on the feed gas composition issues experienced this quarter, specifically what investments or process changes Cheniere is implementing to address these variabilities going forward. He also inquired about the gating items and potential FID timing for Sabine Pass Train 7.

Answer

Jack Fusco, President and CEO, explained that feed gas variability, particularly from Permian gas (increased nitrogen, heavies), has required process changes like running in 'wet mode' at Sabine, using solvents for heat exchangers, and more defrosting. A long-term plan will be implemented next year to enhance resilience. Zach Davis, EVP and CFO, added that the 2026 production forecast includes planned maintenance, especially at Corpus, to address these issues. For Sabine Train 7, Zach stated that the FERC permit, expected late next year, is the primary gating item for FID. They may initiate Limited Notice to Proceed (LNTPs) with Bechtel next year to lock in costs, aiming for 7x CapEx to EBITDA or better, and will retain variable distributions to fund CapEx pre-FID.

John Mackay asked for an update on the feed gas composition issues experienced during the quarter, specifically regarding nitrogen and heavies from the Permian, and the long-term solutions being implemented. He also inquired about the gating items and potential FID timing for Sabine Train 7.

Answer

Jack Fusco, President and CEO, detailed the operational challenges from Permian gas variability, including increased nitrogen and C12+ heavies, and outlined solutions such as running in 'wet mode,' using solvents, and defrosting, with a long-term plan for 2026 to enhance resilience. Zach Davis, EVP and CFO, noted that the 2026 production forecast incorporates planned maintenance for these issues. Regarding Sabine Train 7, Zach Davis stated that the FERC permit is expected late next year, which would precede an official FID, with potential for early spending on long-lead items if financial hurdles are met.

John Mackay asked about the $10 billion shadow backlog, specifically how much is competitive versus waiting for demand to materialize, and the health of the rest of the business given softer RNG performance.

Answer

Kim Dang (CEO) clarified that the $10 billion backlog consists of projects with active customer conversations, estimates, and return analysis, indicating they are actively being pursued. She confirmed the natural gas segment is very strong (beating budget even without Outrigger), terminals are performing well (exceeding budget), products are on budget, with weakness primarily in RNG and CO2.

John Mackay asked for a breakdown of the $10 billion shadow backlog, specifically how much is driven by competitive pursuits versus waiting for demand to materialize. He also inquired about the health of other business segments, particularly if the strength in natural gas is a healthy run rate or includes one-off factors, given softer RNG performance.

Answer

Kim Dang, CEO of Kinder Morgan, stated that the projects in the $10 billion backlog involve active customer discussions, cost estimations, and return analyses. She confirmed that the natural gas segment is very strong, even excluding the Outrigger acquisition, and is expected to exceed its budget. Terminals are also performing well, while Products are on budget. The primary weakness is in RNG and, to a lesser extent, CO2.

John Mackay of Goldman Sachs questioned the composition of the project backlog, where power demand constitutes 50%, and how this mix might evolve relative to LNG growth. He also asked for quantification of the cash flow benefits from new tax rules and their impact on investment strategy.

Answer

CEO Kimberly Dang responded that while LNG is the largest demand driver, she believes forecasts underestimate the breadth of power demand growth across numerous states. CFO David Michels explained that tax reform will provide substantial cash benefits in 2026 and 2027, making KMI a non-material cash taxpayer in those years. Ms. Dang affirmed this additional cash flow will not alter their disciplined investment strategy or return thresholds.

John Mackay asked if the recent $900 million in backlog additions represents a new, more regular pace of smaller project wins or if it was an outsized quarter. He also followed up on permitting reform and the timeline for the Bridge project.

Answer

CEO Kimberly Dang stated that the project outlook remains robust, driven by strong fundamentals in LNG, power/AI, and potential manufacturing growth. She revealed the board had approved another ~$400 million in projects pending contracts. Executive Chairman Richard Kinder emphasized KMI's strategic asset location on the Gulf Coast positions it for continued expansion. On permitting, Dang noted positive engagement with the administration, a recent FERC filing that could accelerate permits by up to 5 months, and favorable actions from other agencies, all aimed at expediting projects.

John Mackay from Goldman Sachs questioned if the projected $2.5 billion annual capital spend is a ceiling and how it's determined. He also asked about potential knock-on effects and operating leverage across the broader Kinder Morgan system from the new large gas projects.

Answer

Kimberly Dang (Executive) clarified the $2.5 billion is an annual average over several years, not a hard ceiling, and can be lumpy but is fundable with internal cash flow. Sital Mody (Executive) and Richard Kinder (Executive) added that these large 'artery' projects create numerous 'capillary' opportunities and operating leverage across their unparalleled footprint, which is central to their growth strategy.

John Mackay from Goldman Sachs inquired about the scale of Kinder Morgan's 'shadow backlog' of potential projects compared to the previous year and requested updates on the Mississippi Crossing and Trident projects.

Answer

President Kimberly Dang confirmed a significant increase in the opportunity set, highlighting the official backlog's growth from $3.8 billion to $5.1 billion year-over-year. Sital Mody, President of Natural Gas Pipelines, elaborated that Mississippi Crossing and Trident are key projects designed to move gas from west to east to meet rising demand, with more details expected in future calls.

John Mackay asked for real-time signals on demand from the refining and export markets. He also questioned how the company thinks about managing its leverage at the low end of its target range amid macro uncertainty.

Answer

An unnamed executive described global refining markets as 'very healthy' with strong crack spreads. On leverage, CEO Willie Chiang and CFO Al Swanson stated that while they won't jeopardize their BBB ratings, they do not intend to operate at the bottom of their leverage range permanently and would use that capacity for strategic investments.

John Mackay asked for a breakdown of the 6 Bcf/d of potential projects between in-basin (Marcellus/Utica) and out-of-basin demand centers, and how supply would reach those areas. He also sought clarification on what 'partnering' on new projects means in practice, whether it involves asset sell-downs, project-level stakes, or other structures.

Answer

President of U.S. Natural Gas Pipelines Tina Faraca explained that demand is widespread across their footprint in states like Ohio, Virginia, and Louisiana, and will be served by their large, interconnected assets like ANR and Columbia, sourcing gas from the WCSB, Appalachia, and Haynesville basins. CFO Sean O'Donnell clarified that the company's bias is shifting towards partnerships to fund growth without balance sheet pressure, rather than selling assets. CEO Francois Poirier added that in Canada, this could involve partnerships with Indigenous communities on new greenfield projects.

John Mackay asked for an update on the potential separation or sell-down of the Mexico business and questioned the change in the growth project breakdown shown on a presentation slide compared to the Investor Day materials.

Answer

President and CEO Francois Poirier reiterated the plan to evaluate a minority interest sale or IPO of the Mexico assets in the first half of 2026, after all major projects are in service, to maximize value. Regarding the slide, Gavin Wylie from Investor Relations suggested it was likely a change in color-coding and offered to clarify offline, while EVP and CFO Sean O'Donnell noted the project pipeline itself had not changed significantly.

John Mackay of Goldman Sachs asked if the 1 Bcf/d NGTL capacity expansion is incremental, and inquired about the expected returns for the Cedar LNG extension and the next steps for a potential CGL Phase 2.

Answer

Executive Stanley Chapman clarified the 1 Bcf/d NGTL expansion represents expected incremental growth over the next 5-7 years. He stated the Cedar project offers modest upside to regulated returns, with potential for more. On CGL Phase 2, he noted there were no new updates as scoping and engineering work continues.

John Mackay inquired about the financial return profile of the McNeill Ranch acquisition, the steps to realize those returns, and the company's broader strategy for future surface or M&A activities.

Answer

President and CEO Amanda Brock detailed the ranch's strategic advantages, including its attractive purchase price, subsurface characteristics, and potential for royalty savings, noting development will be underwritten by long-term contracts. CFO Stephan Tompsett added that any development must compete on a return basis. Founder and Executive Chairman Bill Zartler clarified that large-scale land acquisition is not a core ongoing strategy.

John Mackay inquired about the preliminary 2025 outlook, asking for specifics on the expected mid-single-digit produced water volume growth and the competitive dynamics for acquiring surface acreage to reduce disposal royalties.

Answer

CEO Amanda Brock clarified that while formal 2025 guidance is pending, they anticipate 4% to 7% volume growth, aligning with public forecasts from key customers like Chevron and ConocoPhillips. She also stated that Aris is actively exploring opportunities to both purchase land directly and partner with landowners to lower royalty expenses, highlighting their strong existing permit inventory.

John Mackay asked for Aris's view on growth in the Permian Basin for the second half of 2024 and into 2025, particularly regarding producer efficiencies and the pace of activity in the Delaware versus Midland basins. He also inquired about the company's strategy for disposal capacity and pore space availability and the potential impact on its cost structure.

Answer

President and CEO Amanda Brock confirmed steady performance in the Northern Delaware, consistent with earlier forecasts. Executive David Tuerff added that a relatively flat rig count combined with improved operator efficiencies is driving mid-single-digit production growth, a trend expected to continue into 2025. Regarding disposal capacity, Amanda Brock detailed a proactive strategy, highlighting approximately 90 permits in place across a diversified region and a key alliance with Texas Pacific Land (TPL) that allows Aris to permit and drill for pore space as needed to stay ahead of customer demand.