Jeremy Tonet

Jen said volume growth is going well with 450 MMcf/d of quarter-over-quarter growth despite Q2 shut-ins; July was strong and the year is tracking ahead of expectations.

Jen provided comprehensive overview of Waha dynamics, noting it will get worse before better but Targa has available capacity for producers.

Ben explained that Iran conflict is driving incremental butane demand, product mix shifts free dock space for additional cargoes.

Jen confirmed conservative forecasting with 4 months realized, May visibility, and modest assumptions beyond that.

Meloy attributed resiliency to largest footprint, strong producer relationships, commercial success in 2024-2025 adding to existing growth. 2027 outlook is even more positive than a year ago, supported by bottoms-up producer forecasts with upward revisions.

Kneale explained the increase reflects a larger base (2.5-3 plants/year vs 2), incremental field and compression spending, residue strategy becoming a bigger part of the business, and some carbon capture. Despite higher CapEx, higher EBITDA base means robust free cash flow.

Meloy highlighted best-in-class footprint with well-scheduled active producers providing bottoms-up forecasts that underpin confidence in continued growth in 2027 and beyond, even with a flat to modestly declining rig count.

Kneale confirmed the back-half volume ramp materialized on track to better than forecast, driving record NGL transportation and fractionation. Additional tailwind from NGL and gas marketing opportunities not originally baked into guidance.

Meloy detailed the ramp: a plant's worth of gas in Q2, another in July, and further gains in August. Well connects and Pembrook 2 coming online should drive continued momentum.

Kneale noted strong balance sheet provides flexibility for both organic growth and repurchases. 2026 CapEx depends on activity levels; track record of rationalizing in downturns.

Kneale articulated differentiation through best-in-class footprint, best rock, well-capitalized producers with multi-year drilling programs. Pointed to 2020 COVID resilience as precedent.

Meloy directly addressed trajectory: back-half weighted 2025 with Q1 weather headwinds, 2026 potentially even stronger, driven by commercial wins and producer forecasts.

Kneale explained optimization is not baked into guidance, presenting potential upside, consistent with pattern of beating guidance throughout 2024.

Burke and Dore explained the two markets are at different maturity levels, with ERCOT less tight and pausing its study process while PJM study processes are more localized; interest remains high in both and customers do not need perfect regulatory clarity to contract.

Burke contrasted Vistra's carrot-based, choice-driven approach against a stick approach in some dockets that risks disconnection; Dore added Vistra opposes bring-your-own-new-capacity mandates and thinks IRAS may actually favor co-location with existing resources.

Burke said bilaterals are a real possibility with good sites and can reduce the RBP procured amount, and that batteries, peakers, and CCGTs could bid into the RBP but a spread around $555/MW-day will be needed for certain projects given equipment and EPC costs.

Dore noted customers shifting from sorting alternatives to focusing on actionable deals. Over 3,600 MW added or under development. Vistra viewed as credible partner with demonstrated execution across nuclear, solar, gas, and coal-to-gas conversions.

Moldovan provided transformative disclosure: $22-25 FCF/share trajectory through 2030 assuming excess cash used for buybacks. Cogentrix + Meta add ~$700-750M to 2027. Will formally update guidance after Cogentrix closes.

Moldovan and Burke declined to give specific growth rate. Too many variables in 4-5 year outlook including auctions, hedging, and contracting that haven't materialized. Will update annually.

Burke revealed investing ~$50M/year in people and development to handle record inbound demand. Dore added demand accelerating and lengthening into later years of the decade. All options gas and nuclear remain active.

Burke deferred hedge price disclosure to next quarter per standard cadence. Noted prices laddering up year-over-year through increasing power market.

Burke confirmed pricing spectrum intact: nuclear co-location at top (carbon-free + speed premium), then nuclear FOM, then gas co-location, then gas FOM. Co-location providers (non-hyperscalers) more interested in gas arrangements.

Burke described co-location as 'having a permanent roommate' lasting decades. Activity level picked up this quarter but cautioned conversations ebb and flow. Focused on getting the right deal, not just any deal.

Burke gave extensive comparison: PJM cap/floor sends better investment signal (30 GW gas built over past decade). ERCOT has not sent same signal for dispatchable resources. First 8-10 GW of ERCOT data center load can be served by existing capacity.

Moldovan confirmed buyback program runs continuously under 10b5-1 plan. Has never been paused, not even during Energy Harbor or minority interest acquisitions.

McFarland clarified nuclear capital is primarily fuel (categorized as capital), subsequent license renewal, and maintenance. No new nuclear build capital in the five-year plan.

Blue declined to pin specific date on early 2027. Weather delays through July 2027 within current $11.05B budget. Beyond that, $150-200M per quarter. Cautioned against drawing conclusions from early-stage installation during worst weather season, citing monopile precedent of slow start then fast finish.

Blue confirmed PJM interim deliverability study requested annually. Some network upgrades may not be done when CVOW finishes. Assumed 50% deliverability for rider, will update if assumption needs adjustment.

Blue highlighted Virginia as most nuclear-friendly state but cited first-of-a-kind costs, cost overrun risk, and balance sheet protection as key gates. Amazon MOU for SMR at North Anna 3 remains in progress.

Blue acknowledged elevated transformer demand industry-wide but said Dominion's scale and long supplier relationships provide an advantage. IRP generation dates aligned with supply chain timelines.

Blue confirmed inter-array cable work is on track despite non-linear production pattern. Cautioned against quarter-over-quarter extrapolation.

Ridge confirmed willingness to opportunistically pull forward ATM issuance for 2026, noting forward-settled sales as an available and attractive option.

Ridge quantified $175M annual transfer credits, mostly from CVOW PTCs. If transferability changes, tax equity is a reasonably efficient replacement. Watching carefully but confident in mitigants.

Blue confirmed no new data, final PJM number due in July. Expects any revision to be much smaller magnitude than the last $900M update.

Blue explained data center load growth actually helps affordability by spreading fixed costs and highlighted strong bipartisan political support for expansion.

Blue characterized the upcoming biennial as straightforward with no exotic elements, strong positioning on reliability and affordability, result expected by end of November.

Chad said commercial interest is strengthening, backlog supported by multiple customers beyond the first; direct.

Zamarin confirmed robust demand, noted Neo as largest project to date, and said backlog remains as robust if not more so than Analyst Day.

Zamarin outlined two key reform priorities: 401 permitting process and judicial reform. Said they are hopeful Senate will act this year.

Zamarin described integrated wellhead-to-water strategy connecting gathering through Transco and LEG to Line 200 and LNG terminal. Offtake provides window to international markets for producer customers. Not a speculative LNG entry.

Zamarin said backlog strengthened to over $5 billion committed with 6 gigawatts in pipeline. Expects additional projects through end of decade and beyond. Geography is diverse across entire footprint.

Zamarin highlighted Power Express and NESE milestones on Transco. Larsen said Rockies Columbia Connector open season closing with great interest. Opportunities across entire footprint.

Wingo brings midstream and upstream perspectives. Found Williams strategy robust and comprehensive. Plans to execute existing plan and capture opportunity set. Praised team culture and Chad's leadership.

Armstrong said gas demand call coming stronger than expected with visible volume growth in Q1 and April. If oil softens further, rigs likely rotate to gas areas. Expects choppy but upward trajectory.

Zamarin credited cross-organization collaboration combining gas supply, pipeline capacity, and construction capabilities. Armstrong added long-term Solar turbine vendor relationships provide equipment access advantage.

Dunn confirmed opportunity to provide gas-fired power more cost-effectively than grid in Virginia, Pennsylvania, Ohio. Solution addresses speed, reliability, and consumer cost concerns.

Armstrong highlighted Salt Lake and Wyoming as well-positioned areas. Noted grid constraints and state politics will determine winners. Hyperscalers looking at resource-rich areas like Wyoming for Chapter 2 projects.

Poroch confirmed demand response is part of every conversation and tied it to bilateral contracting flexibility across the three jurisdictions.

Womack cited 100 MW projects in Mississippi and rising pipeline activity but offered no contracted figures for the state.

Poroch cited exhaustive scenario planning with durability built in to achieve at least 7% growth. Upside from signed contracts, population in-migration, business expansion, and other momentum factors.

Womack emphasized rate stability through 2027-2028 in Georgia and Alabama, with large load pricing designed to benefit existing customers and provide continued rate stability into the future.

Womack praised federal nuclear support (Westinghouse-Cameco-Brookfield, executive orders) but said Southern Company is not ready to announce new nuclear until all financial risks are mitigated.

Tucker said pipeline investments are tied to Southern Natural Gas with Kinder Morgan, driven by new combined cycle construction and overall load growth in the area including co-ops and munis.

Womack couldn't specify timing but confirmed advanced discussions on multiple projects. Tucker noted investment is already occurring: 1,000+ MW of data center projects, transmission/distribution builds, Alabama Power generation acquisitions.

Womack cited variables including large load pricing benefits, fuel adjustment recovery timing (June next year), and Hurricane Helene storm cost recovery, but said it's too early to specify filing details.

Tucker said impact to FFO/debt would be only 10-20 basis points if transferability was lost. The company is engaging policymakers to express the customer benefits of tax credits.

Womack confirmed data center momentum expanding from Georgia into Alabama (Meta project) and Mississippi (Compass project), with significant capacity opportunities across both states.

Management confirmed 2.2 GW of signed ESAs exceed the 1.2 GW plan assumption and would represent upside to sales and earnings. September IRP update will provide comprehensive refresh.

Management detailed several gigawatts of interest at engineering study stage in both states, ongoing expansion conversations with existing hyperscalers, and optimism on near-term ESA conversions.

Lyons confirmed pipeline unchanged at 2.3 GW but emphasized developers are requesting expansion studies and ESA negotiations are progressing as expected.

Moehn confirmed near-term slots secured for 2027-28 simple cycles, combined cycle RFP to close in 60-90 days, and beyond that exploring flexibility.

Moehn confirmed gas access is secured for all three generation sites, Meramec has existing supply, Rush Island requires repurposing, combined cycle has a nearby transmission line.

Lyons framed credits as customer savings (~$2B over 10 years) and advocated for retention. Moehn confirmed balance sheet can absorb loss without additional equity.

Lyons explained 2.3 GW agreements give greater confidence in 5.5% sales CAGR but actual load depends on ramp schedules yet to be finalized.

Lyons framed legislation as helping close regulatory lag to allowed returns rather than providing explicit earnings upside sizing.

Moehn attributed minimal equity issuance to historically conservative balance sheet management entering the investment super-cycle.

Maddipati declined to bias within the range but confirmed the NorthStar repositioning is already incorporated into the 2027 guide, with updates to come through the normal planning process.

Maddipati identified engineering and development platform costs as the category but gave no magnitude, leaving the size of the efficiency unquantified.

Garrick emphasized CMS's track record through all political environments. As one of Michigan's largest investors, property taxpayers, and union job providers, CMS engages gubernatorial candidates with policy solutions to improve affordability. Energy law and staggered 6-year commissioner terms provide structural stability.

Garrick corrected to $25B+ and outlined three vectors: more electric distribution reliability spending, approved REP renewables with tax credit safe harboring through 2029, and early IRP battery storage and gas capacity. All three expected to contribute to next 5-year plan at Q4 call.

Garrick said CMS is evaluating the mix of simple cycle and combined cycle but confirmed both battery and gas capacity are needed for retiring facilities and existing load growth. Well-planned and well-prepared.

Rejji confirmed the deferred accounting order approval is NOT assumed in guidance. Conservative approach despite making a compelling case.

Garrick said staff position is constructive, case is straightforward (gas pipe replacement, safety). Open to settlement before August PFD, will push on ROEs in rebuttal.

Garrick used a sausage-making analogy to dismiss process concerns, pointed to track record of constructive outcomes across 2022-2024.

Rejji quantified DIG loss at over 50% of prior contribution, offset by existing thermal fleet and new renewable CODs in H2 2025.

Management declined to predict Waha pricing precisely but expects it could tighten again before 2027 as shut-in and backloaded gas returns; prefers a healthy Waha supporting producer economics.

Jim and Natalie confirmed producer discipline; Tug noted it's about the back of the futures curve lifting, not a specific price level.

Randy estimated 50-65% of 2027 CapEx is not yet committed to specific FID'd projects, providing significant flexibility.

Tug confirmed system optimization during winter events but cautioned against expecting Uri-level uplift.

Randy confirmed 55-60% of ~$1B free cash flow allocated to buybacks in 2026, mix of programmatic and opportunistic purchases.

Jim declined to share succession details but expressed confidence in the management bench and said he's not worried about succession plans.

Randy outlined path to ~$1.5B available for buybacks and debt paydown in 2026 as growth CapEx declines and cash flow grows.

Graham noted PDH-1 had minor blip but ran well post-turnaround. PDH-2 has design issue with licensor limiting rates; targeting upper 90% utilization long-term.

Jim expressed skepticism on permit reform timing. Randy noted Congress following through on election platform but no surprises yet.

CEO pointed to Southeast expansion needs, MVP expansions and hub-related laterals as the pipeline opportunity set.

CEO described SMR evaluation and risk-sharing structure requirements but gave no dated timeline beyond the Duane Arnold recommissioning.

CEO ruled out LNG participation outright; CFO framed the strategy as customer solutions rather than merchant export exposure.

John said dedicated SMR development team evaluating both existing nuclear sites and greenfield. Prefers creating competition among suppliers rather than locking into one. Any deal needs right commercial terms with risk sharing and capped financial exposure. Mike added SMRs are upside to base plan, not embedded in expectations. Four-way structure needed: OEM, developer, hyperscaler, government.

John acknowledged some wind additions in 2028-2029 backlog but said trend still favors solar and batteries. National footprint means interest varies by product and region. Not characterizing as green shoots for wind specifically.

John highlighted fast build times, early/late-stage project inventory, and significant cost advantage over gas and nuclear. Recontracting of decade-old PPAs into higher power market creates embedded value. Combined with gas development, nuclear, and transmission business.

John emphasized existing assets serve current demand; incremental generation must be built. NextEra uniquely positioned with development teams in 49 states. Very few companies have been building for last 2 decades.

GEV framework advancing on customer origination. Hosted Deploy event with GE Vernova CEO targeting large-scale load. Hyperscalers prefer front-of-meter solutions requiring 3-way conversation with utilities. Behind-the-meter requires redundancy premium but attractive where grid access takes 5-7 years. NextEra uniquely positioned to combine gas with renewables for carbon-neutral solutions.

Rebecca said increased demand for natural gas is for capacity value while renewables provide lowest-cost energy. Great pairing customers are interested in. Behind-the-meter gas discussed but not expected to be prevalent solution. Existing grid provides huge value.

Asked what is new on the Slide 13 growth/capital-allocation table; Shane explained the new $0.20 floor reflects $2.2 billion of accretive buybacks completed since March.

David Dardis responded: appreciate PJM's commitment to competitive markets, support for energy/reserve co-optimization and bilateral contracting. Option B (differential reliability) raises legal questions. CEO added more revenue should have been recognized in energy market, putting less strain on capacity market.

Joe confirmed critical items completed, plant condition better than anticipated. Main transformer, fuel, and staffing all addressed with no new challenges emerging.

Jim McHugh noted power has outperformed gas with longer-duration heat rate and spark spread expansion driven by data center load growth and supply-demand fundamentals.

Joe expects states to revisit fossil retirement timelines, suggested emissions banking approach for extensions. Strongly defended competitive market model against monopoly-build arguments.

Joe explained ELCC for demand response rises from below 70% to over 90% in next auction, significantly improving economics. DR requirements expand from 18 to 24 hours.

Joe and David Dardis said resolution could come in a handful of months through either settlement or FERC directing PJM tariff amendment.

Joe explained customers are pivoting to front-of-meter on-grid deals where clarity exists, working with utilities that move studies quickly.

Walt pointed to the earnings deck showing Q1 as the lowest, with the EBITDA curve expected to slope upward through the year, potentially with enhanced back-half volume benefits.

Walt highlighted operating leverage on Bakken and West Texas LPG pipelines with no incremental CapEx needed as volumes grow. Potential for north-south differentials once Medford comes online.

Pierce confirmed all acquisitions on pace: Magellan leading synergies given longest tenure and asset overlap, EnLink on track but contractual rollovers take time, Medallion benefiting from balance sheet integration.

Pierce attributed the delta to two factors: 100 MMcf/d lower volumes from reduced drilling activity and narrowing spreads from lower commodity prices. Noted 2026 project completions (Denver, Medford, Shadowfax) will carry momentum into 2027.

Walt noted attractive multiples, strategic connectivity to Medallion assets, and continued 50-50 governance structure (not consolidated).

Sheridan detailed Easton connections (Galena Park, East Houston, Pasadena MVP) completing in Q3, enabling more blending volume and reduced costs.

Pierce cited LNG demand growth, AI data center demand, and continuing global LPG/LNG demand as catalysts independent of commodity cycle uncertainty.

Sheridan framed re-contracting as constructive win-win bundling conversations, noting producers see value in ONEOK's integrated services across the value chain.

Dan said interest is in both but skewed to new generation, reflecting a nationwide preference to pair new load with incremental supply.

Cregg explained hyperscalers follow financial incentives to other states; NJ lacks the tax incentives to attract large-scale data center development.

Cregg noted data center interest has leveled off after sharp increase last year. Still estimates 10-20% of total interest may materialize based on history.

LaRossa stated big nuclear is the highest and best use of PSEG's property given its early site permit (technology agnostic). Also has a gas-ready site with pipes and wires. Would enable SMRs if policymakers prefer that direction.

LaRossa outlined willingness for regulated gas generation, large-scale solar, regulated storage, and enabling new nuclear (hosting without own capital). Both gubernatorial candidates support all-of-the-above strategies.

Cregg identified Pennsylvania as having a more forward-leaning appetite enabling bigger scale opportunities, while New Jersey has interest but at smaller scale and without comparable incentives.

LaRossa said offshore wind friction creates no negative impact since PSEG had nothing in the plan to the East. Potential opportunities to the West depending on resource adequacy solutions.

LaRossa cited consensus for upper half of the collar range but emphasized no double-digit customer bill increases expected since the catch-up has already occurred.

Management expressed high confidence in converting late-stage pipeline to ESAs over next 12 months. Savoy highlighted speed-to-power retooling, noting Q1's 2.7 GW exceeded half of all 2025 signings.

Sideris confirmed multiple levers to mitigate rate increases. Tax credits available now; Carolina utility combination effective January 2027 will add savings over time.

Sideris said legislative discussions around data center protections and fuel cost sharing are aligned with existing contract provisions. Views potential legislation as codifying what DUK already does.

Harry said the October IRP filing will continue the all-of-the-above approach including gas, batteries, uprates, and solar. The new NC bill removes the 70% carbon reduction requirement.

Brian acknowledged tough Q2 2024 comp and noted large customers being cautious amid tariff/tax uncertainty but running to firm orders. Expects 1.5-2% growth intact for the year.

Lynn emphasized long-term strategy alignment with federal and state aspirations. Noted Duke joined a DOE consortium with TVA for new nuclear technologies targeting 2030s deployment.

Harry noted Indiana growth is mainly advanced manufacturing with some data centers in the pipeline, not at Carolinas levels. Highlighted Indiana's constructive business-friendly environment.

Partial: redirected to DOE fossil loan work and framed nuclear at the retained site as a much longer-term option.

Partial: confirmed the drivers are all upside and noted the company is already at the high end of the range in 2028, but deferred quantification.

Described VLC tariff as fair, balanced, and developed collaboratively with large customers. Received positive feedback from developers.

Comprehensive response: actively safe harboring, 80% of transfers from in-service projects, limited impact expected from repeal.

Confirmed discussions with multiple potential customers without naming specifics. Emphasized need for purchase cancellation agreements.

Deferred CAGR update to Q3 call rather than providing preliminary view. Reasonable given early stage.

Acknowledged RICE unit experience but noted it's part of a broader mix with CTs; didn't claim clear differentiation.

Mihalik said Board raised dividend 2% and is targeting 50-60% payout ratio. Dividends assumed to increase by shares outstanding, with Board making future discretionary decisions. 115 consecutive years of dividend payment.

Mihalik confirmed the 9% or above in 2028-2030 is year-over-year growth, not a CAGR from 2026.

Fehrman acknowledged reconductoring adds incremental capacity but emphasized the scale demands dramatic 765kV backbone additions across PJM, SPP, MISO, and ERCOT.

Fehrman broke down incremental capital: $7B AEP Texas transmission, $3B PSO generation, $2B I&M generation, plus distribution and miscellaneous. Not looking to sell assets as a strategy.

Fehrman confirmed fuel cell costs covered by individual large customers under standalone contracts requiring state commission approval. Michalek deferred capital specifics to future disclosures.

Fehrman described extensive stakeholder engagement. Securitization option offered to support affordability is not in current financial plans. Positive feedback on approach so far.

CEO outlined: Oracle small in 2026 then shoots up exponentially to full ramp over couple years. Google starts small, expands to 1 GW by end of 2028. Oracle expected to attach to grid end of 2026.

CEO explained Oracle benefits higher per unit since only battery storage needed (using existing capacity). Google requires additional baseload generation identified through IRP, so benefit per unit is somewhat less but still sizable. All future deals must provide affordability benefits per law.

CFO noted $34M of $50-60M annual guidance earned in Q1, with potential continued favorability that would be used to strengthen 2026/2027.

CFO confirmed no change to Vantage utility-like pivot strategy; all projects are safe harbored or under existing IRA provisions.

CFO confirmed minimal equity through 2027 supported by strong cash flows and tax credit monetization, with modest increases in 2028+.

Management detailed Vantage pivot to cogeneration, water treatment, compressed air, and early-stage carbon capture with IRRs north of 10% unlevered after tax.

John broke the $1.8B into $700M Connecticut securitization, ~$450M New Hampshire storm costs, and the balance from Connecticut carrying charges he still expects to pursue.

Nolan praised the litigated case as constructive, fair, and transparent despite being the first litigated case in memory. Asked for $103M net of storms, received $100M with 9.5% ROE. Moreira added the PBR structure and revenue baseline are valuable for future rate increases.

Moreira confirmed strong S&P position already. For Moody's, highlighted 200+ bps improvement on rolling 12-month basis in one quarter. Expects momentum to continue with 13% handle coming in following quarters. Did not provide specific Q2 end figure.

Nolan highlighted $2.4B debt reduction from Aquarion plus sustainable future cost-revenue alignment. Moreira noted FFO-to-debt will continue to enhance contingent on capital forecast updates.

Moreira clarified Aquarion earnings are included through expected closing date, not moved to discontinued ops. Full benefit of debt paydown from sale proceeds expected in 2026.

Butler and Innocenzo cited constructive settlements and ongoing discussions with the governor office and PUC, but gave no filing date or specific trigger.

Jones listed roughly five drivers behind the range and Khouzami pointed to two MISO Tranche 2.1 bids in Iowa with a decision expected in the fourth quarter.

Jeanne emphasized executable and defensible growth, noting proposals in current PJM window with clarity expected by year-end. Focused on 7-8% rate base growth upper portion.

Jeanne detailed TSA structure protecting existing customers while firming commitments. Filed large load tariff at ComEd for all loads over 50MW. Slide 13 shows 47GW filtering through phases.

CFO said Oklo continues to evaluate M&A at the scale of ARMEC and CEI, framed as a build-versus-buy accelerator for asset-deployment capability where a strong team can be brought in-house at the right price.