David Smith is a Vice President and equity research analyst at Truist Securities, focusing on the U.S. biotechnology sector and select financial companies, including coverage of Bank of New York Mellon Corporation. He has issued investment ratings with approximately 60% Buy and 40% Hold recommendations and, according to TipRanks, his recent performance shows an average return per rating of -2.3% based on a 1-year holding period, with a success rate of 0%. Smith joined Truist Securities’ equity research team in early 2025, having built his expertise in financial analysis with prior experience in the industry and holding the CFA designation. He maintains active professional credentials and is recognized for his analytical rigor in equity research.
David Smith of Truist Securities asked a technical question about capital, specifically if there would be any difference in how preferred shares would qualify for Tier 1 treatment after Flagstar Bank N.A.'s holding company was consolidated down to the bank level.
CFO Lee Smith confirmed that there would be "no change at all" in how the preferred shares would qualify for Tier 1 treatment.
David Smith asked a technical question regarding capital, specifically if there would be any difference in how preferred stock would qualify for Tier 1 treatment after the holding company was consolidated down to the bank.
Lee Smith, Chief Financial Officer, confirmed that there would be no change at all in how preferred stock will qualify for Tier 1 treatment.
David Smith of Truist Securities inquired about any potential downsides to merging the holding company into the bank and sought confirmation that the bank is still on track for GAAP profitability in Q4 2025.
General Counsel Bao Nguyen stated there are no downsides to the merger, as nearly all operations are already in the bank and it streamlines regulation. Senior Executive Vice President & CFO Lee Smith gave an emphatic 'absolutely' to confirm that the company remains on track to achieve GAAP EPS profitability in the fourth quarter of this year.
David Smith with Truist Securities inquired about the competitive landscape impacting C&I loan declines and average deposit cost increases, seeking insights into expected trends for the fourth quarter and the upcoming year. He also asked about Valley National Bancorp's capital allocation strategy, specifically balancing share buybacks against capital conservation for long-term organic growth given current capital ratios and loan growth projections.
CFO Travis Lan explained that spot deposit costs declined, with further reductions expected, and noted the competitive environment for new deposit relationships. President of Commercial Banking Gino Martocci observed strong demand and ample liquidity in the loan market, leading to some spread declines. Regarding capital, CFO Travis Lan indicated that with CET1 nearing its target, share buybacks would increasingly be a source of capital deployment, reflecting confidence in internal investments.
David Charles Smith asked about the competitive landscape impacting C&I loan declines and deposit cost increases, seeking expectations for Q4 and 2026. He also inquired about Valley National Bancorp's capital allocation strategy, specifically the buyback opportunity versus conserving capital for organic growth, given current CET1 and tangible book value.
Travis Lan, CFO, explained that spot deposit costs declined, with further reductions expected into 2026, despite a competitive environment for new relationships. Gino Martocci, President of Commercial Banking, noted strong demand in C&I and CRE, ample market liquidity, and some spread declines. Regarding capital, Travis Lan, CFO, stated that while the near-term CET1 target is 11%, the bank is comfortable in a 10.50%-11% range, and buybacks will be an increasing source of capital deployment given confidence in investing in the company.
David Smith from Truist Securities asked about the competitive landscape in technology and software banking and how Valley is adapting. He also inquired about the potential impact of the New York City mayoral race on the bank's rent-regulated multifamily portfolio.
Chairman & CEO Ira Robbins explained that Valley's tech banking capabilities were significantly enhanced by an acquisition in 2022, providing a strong infrastructure and deep connectivity to the Israeli market, which they are now leveraging for domestic expansion. EVP & Chief Credit Officer Mark Saeger stated that any political pressure would likely be confined to their small ($600M) and granular rent-stabilized portfolio, which they feel is adequately provisioned and was underwritten on in-place cash flows.
David Smith from Truist Securities asked about the competitive landscape in the technology and software banking sector and how Valley is adapting its strategy. He also questioned the potential impact of the New York mayoral race on the bank's rent-regulated multifamily portfolio.
Chairman & CEO Ira Robbins explained that Valley's tech banking capabilities, acquired via the Leumi transaction, provide a significant infrastructure advantage, particularly with its strong connectivity to the Israeli market. EVP & Chief Credit Officer Mark Saeger addressed the NYC portfolio, stating that the $600 million rent-stabilized portfolio is granular and was underwritten on in-place cash flows, mitigating risks from future rent increase limitations, regardless of the mayoral election outcome.
David Smith from Truist Securities asked about the competitive landscape for banking the technology and software sector and how Valley is adapting. He also questioned the potential impact of the New York City mayoral race on the bank's rent-regulated multifamily loan portfolio.
Chairman & CEO Ira Robbins explained that Valley's technology banking capabilities were significantly enhanced by the 2022 Blues acquisition, which provided critical infrastructure and an experienced team now being leveraged for domestic expansion. EVP & Chief Credit Officer Mark Saeger addressed the NYC portfolio, stating the rent-stabilized portion is a small and granular $600 million portfolio underwritten on in-place cash flows, which mitigates risk regardless of political outcomes.
David Smith from Truist Securities asked about the competitive landscape in the technology and software banking sector and how Valley is adapting. He also inquired about the potential impact of the New York mayoral race on the bank's rent-regulated multifamily loan portfolio.
Chairman & CEO Ira Robbins explained that Valley's technology banking capabilities were significantly enhanced by the 2022 Leumi acquisition, which provided an experienced team and robust infrastructure that is now being leveraged for domestic expansion. EVP & Chief Credit Officer Mark Saeger addressed the NYC portfolio, stating it's a small, granular portfolio of $600 million that was underwritten to in-place cash flows, mitigating risks from potential political or regulatory changes.
David Smith from Truist Securities asked about the competitive landscape for banking the technology and software sector and how Valley is adapting its strategy. He also inquired about the potential impact of the New York City mayoral race on the bank's rent-regulated multifamily loan portfolio.
Chairman & CEO Ira Robbins explained that Valley's competitive advantage in technology banking stems from the experienced team and infrastructure acquired with Leumi, which provides a strong platform for domestic expansion. EVP & Chief Credit Officer Mark Saeger addressed the NYC political situation, noting that Valley's $600 million rent-stabilized portfolio is small, granular, and conservatively underwritten to in-place cash flows, mitigating significant risk from potential policy changes.
David Smith asked for more details on Western Alliance Bancorporation's mortgage assumptions within its overall earnings sensitivity guide for down rates, specifically if there's limited mortgage upside given ECR beta and NII sensitivity.
CFO Dale Gibbons explained that a key factor is the valuation of Mortgage Servicing Rights (MSRs) relative to hedges, with compressing spreads potentially leading to higher revenue. He noted that the Mortgage Bankers Association (MBA) projects slightly better purchase activity in Q4. President and CEO Ken Vecchione added that the MBA forecasts $2.2 trillion in mortgage activity for 2026, expressing optimism for next year's mortgage revenue. In a follow-up, Dale Gibbons stated that the preponderance of the offset to NII asset sensitivity in a down-rate scenario would come from the mortgage side, though ECR benefits also contribute.
David Smith asked for more details on Western Alliance Bancorporation's mortgage assumptions in its overall earnings sensitivity guide for down rates, specifically if there's little mortgage upside. He also requested a rough sizing of the offset to NII asset sensitivity from ECR benefits versus mortgage benefits in a down-rate environment.
CFO Dale Gibbons explained that compressing mortgage spreads to historical levels could lead to higher mortgage revenue, as volatility has not favored them. He noted that while the Mortgage Bankers Association projects better Q4 activity, Western Alliance Bancorporation expects a slight seasonal slip. President and CEO Ken Vecchione added that the MBA projects a 10% rise in mortgage activity for 2026. Dale Gibbons indicated that the preponderance of variability and improvement in earnings at risk would come from the mortgage side, though both ECR and mortgage contribute to the offset.
David Smith sought to understand the moving parts behind the deposit cost outlook, specifically the drivers of the significant sequential decline implied for Q4 2025.
CFO Dale Gibbons attributed the outlook to a mix shift towards lower-cost HOA deposits and growth in other areas like digital and corporate trust. He also highlighted that the forecast incorporates two anticipated rate cuts in September and December, which would significantly lower ECR-related costs in the fourth quarter.
David Smith asked for more color on the relative strength in FX trading and securities commissions, inquiring about the initiatives driving this growth and distinguishing how much of the strength is attributable to Northern Trust's strategic actions versus broader favorable market volumes.
Michael O'Grady, Chairman and CEO, attributed the strong performance in capital markets to both strategic execution and favorable market conditions. He detailed the strategy of building a more durable capital markets business by evolving activities into services, such as becoming an outsourced trading provider for asset managers (generating recurring brokerage commissions) and offering currency management as an automated service. O'Grady also mentioned expanding liquidity capabilities, including FICC repo, to diversify the business and enhance its financial profile.
David Smith requested more color on the relative strength in Northern Trust's FX trading and securities commissions, asking for details on the initiatives driving this growth and distinguishing between market benefits and internal strategic efforts.
Chairman and CEO Michael O'Grady attributed the strong performance in capital markets to both strategy execution and favorable market conditions. He highlighted the strategy of building a more durable business by becoming an outsourced trading provider for asset managers, offering currency management as a service, and expanding liquidity capabilities through FICC repo, leading to more recurring and predictable revenue streams.
David Smith asked for color on the drivers behind the strong deposit growth in the quarter and requested more detail on which segments within asset servicing are showing the strongest growth.
EVP & CFO David Fox attributed the higher deposits to a 'risk-off' environment and some large, concentrated client deposits, noting that levels are beginning to normalize in Q3. Chairman and CEO Michael O'Grady highlighted the 'upmarket of asset owners' as a key area of strength in asset servicing, citing several significant recent client wins.
David Smith asked how market volatility impacts new business and client attrition across segments and sought confidence that the company is making necessary growth investments while simultaneously reducing expenses, given that organic flows appear to be lagging peers.
CEO Mike O'Grady stated that while volatility can cause clients to pause decisions, especially on the wealth front, it hasn't had a significant impact yet and can build the pipeline. He affirmed confidence in funding growth, explaining that productivity initiatives create the capacity to invest in key areas like alternatives, family office services, and new ETF launches, which are crucial for driving organic growth.
David Smith noted Northern Trust's elevated capital levels compared to peers and asked about near-term capital deployment plans and target capital ratios. He also inquired about the expected quarterly cadence of Net Interest Income (NII) throughout 2025, given the full-year guidance.
Chairman and CEO Michael O'Grady confirmed capital levels are strong, enabling higher share repurchases which are expected to continue at a similar pace in 2025, with a total payout ratio at or above the 78% seen in 2024. Chief Financial Officer David Fox explained that predicting the quarterly NII cadence is difficult due to the company's liability-driven model and the need to accommodate unpredictable client activity, such as loan demand.
David Smith inquired about the bank's transition from recent modest loan growth shrinkage to projected low to mid-single-digit growth, asking about the current risk appetite, any impact from the one-off borrower situation, and how the overall risk appetite might evolve.
Chief Credit Officer Derek Steward stated that the bank would continue its historical underwriting practices, and the recent incident would not change its approach to growth. He also noted ongoing successful payoffs or improvements in commercial real estate criticized and classified loans over the last six months.
David Smith from Truist inquired about Zions Bancorporation's current risk appetite, specifically whether the recent one-off borrower situation has influenced it, and how the overall risk appetite is expected to evolve over the next few quarters, particularly in light of the projected transition from modest loan growth shrinkage to low to mid-single-digit growth.
Chief Credit Officer Derek Steward affirmed that the bank will continue its historical underwriting practices, stating that the recent incident will not change their approach to growth. He also noted ongoing successful improvements and payoffs in commercial real estate criticized and classified loans over the past six months.
David Smith from Truist Securities asked whether current GAAP equity levels constrain the bank's ability to accelerate loan growth, given the solid credit performance and positive customer sentiment.
CFO Ryan Richards stated that the bank does not feel capital constrained and is oriented towards pursuing organic growth, supported by investments in marketing and hiring revenue producers. President & COO Scott McLean added that intensified client and prospect calling programs are underway to generate more opportunities and compete effectively.
David Smith with Truist asked if the Apex investment and State Street's integrated model create potential opportunities on the investment management side, in addition to investment services.
CEO Ron O’Hanley confirmed that the rise of wealth management creates significant opportunities for investment managers, with over 20% of State Street's AUM already associated with wealth. He highlighted growth in low-cost S&P funds and emphasized that the strategy involves providing infrastructure and servicing capabilities to clients, along with user-friendly, low-cost asset management exposures.
Asked if the revenue impact of an Alpha client win could be calculated with a simple formula based on the number of mandates and total servicing fee wins, and what accelerating Alpha penetration means for revenue rates.
Management explained that it's not that straightforward, as Alpha wins vary significantly in size, complexity, and scope (e.g., whether it includes a move from on-prem to SaaS). Therefore, a simple formula cannot be used. However, they confirmed that the Alpha platform is a key factor in accelerating overall sales and new business wins.
Asked for metrics on the Alpha platform's penetration, its key benefits like retention versus pricing, and an explanation for the asymmetry in U.S. deposit betas between the hiking and potential cutting cycles.
Executives highlighted that Alpha provides a distinctive offering that secures longer-term contracts (7+ years) and that 35 clients have been announced. On deposit betas, they explained that the recent 65% beta is within the general zone seen during the hiking cycle, and quarterly variations are often artifacts of client mix and volume changes rather than a fundamental shift in pricing strategy.
David Smith of Truist Securities asked about the current penetration of the Alpha platform, its medium-term targets, and its primary benefits. He also sought an explanation for why the Q4 U.S. deposit beta was lower than the beta experienced during the rate-hiking cycle.
CEO Ron O'Hanley and incoming Interim CFO Mark Keating highlighted that Alpha is a distinctive front-to-back offering that secures longer-term contracts (7+ years) and drives servicing wins, with 35 clients announced and 25 installed. CFO Eric Aboaf addressed the deposit beta question, stating that while betas steepened during the hiking cycle, the current 65% beta for U.S. dollars is in the same 'general zone' and that quarter-to-quarter figures can be affected by client and deposit mix shifts.
David Smith asked about Webster Financial's prioritized investment opportunities and whether lifting the Category 4 regulatory threshold would free up investment dollars for initiatives directly related to revenue or profitability.
John Ciulla (CEO) confirmed that lifting the Category 4 threshold would allow Webster to avoid or spread out related costs, enabling redeployment of funds into new business initiatives. These include continued digitization across business lines, enhanced treasury management capabilities, new teams in key middle market segments, and adjacent opportunities within HSA and Amitros. Mr. Ciulla expects more clarity and details on these investment plans to be shared in January.
David Smith of Truist Securities asked if there could be a further benefit to Net Interest Income (NII) from the recovery of interest on non-accrual loans as credit quality improves.
Chairman & CEO John Ciulla acknowledged that a downward trend in non-performers should be a net positive but stated that the company's forecast does not assume a material NII impact from such recoveries. He explained these events are often unpredictable quarter-to-quarter.
David Smith of Truist Securities, Inc. asked about F.N.B.'s balance sheet sensitivity to interest rates, specifically how its short-term asset-sensitive, medium-term neutral, and long-term liability-sensitive profile would react to the ongoing Fed cut cycle and impact Net Interest Income (NII). He also sought insights into lessons learned from markets where F.N.B. did not grow deposit market share, compared to the 75% where it did.
CFO Vincent J. Calabrese stated that F.N.B. is essentially neutral on interest rate sensitivity, aiming to maintain this position while driving NII growth through loan and deposit expansion, noting positive contributions from new loan originations and securities reinvestment. Chairman, President, and CEO Vincent J. Delie explained that non-growing deposit markets often involve dominant large players or areas with minimal F.N.B. investment, emphasizing that the focus is on leveraging success in the 75% of growing markets and using daily scorecards and AI to address underperforming areas.
David Smith asked about potential pressure on money market fund fee rates from stablecoins and falling interest rates, and how the proportion of multi-line asset servicing wins compares to previous periods.
CEO Robin Vince viewed the evolution of money markets and stablecoins as an opportunity, not turbulence, highlighting BNY Mellon's broad participation and investment in digital assets to manage the transition. CFO Dermot McDonogh confirmed that the trend of multi-line asset servicing wins is meaningfully higher, though specific historical metrics are still being developed.
David Smith asked about potential pressure on money market fund fee rates due to the rise of stablecoins and falling interest rates. He also inquired how the 'almost half' of asset servicing wins being multi-line solutions compares to prior periods.
CEO Robin Vince viewed the evolution in money markets as an opportunity, not turbulence, highlighting BNY's broad participation and investment in digital assets to serve on-chain capabilities. He sees stablecoins as offering mobility that BNY can leverage through its transaction businesses. CFO Dermot McDonogh stated that BNY is developing metrics to track multi-line solutions more precisely, but confirmed that the trend is 'meaningfully higher' than last year, with more solutions delivered to existing clients.
David Smith from Truist Securities asked if BNY Mellon feels it is 'over-earning' in any areas given the strong results, or if the goal is to improve profitability from current levels. He also pushed on why the company isn't investing more aggressively, with expense growth above 3%, to capitalize on the strong momentum.
CFO Dermot McDonough responded that the firm is focused on getting '1% better every day' across all businesses and does not feel any area has reached its maximum potential. CEO & Director Robin Vince added that the company is not allowing itself to think about ceilings on returns or margins, comparing itself to other platforms companies, not just banks. Regarding investment, Vince explained that while they constantly push businesses for investment needs, the firm maintains financial discipline and agility, avoiding betting on a perfect environment at the start of the year.
David Smith from Truist Securities asked about the sustainability of Net Interest Income (NII) from repo and fed funds. He also questioned the high deposit beta and when it might level off, and how the macro environment affects client willingness to switch service providers.
CFO Dermot McDonogh explained that while the repo business is performing well, it constitutes a small part (around 5%) of the overall NII. He noted that BNY's deposit beta has historically been high due to its sophisticated client base and that the marginal beta is around 100%. CEO Robin Vince added that BNY's broad platform allows clients to easily move activity to them in turbulent times, and while major, distracting projects might be paused, most of BNY's services don't fall into that category.
David Smith from Truist Securities asked about the resilience of AUCA despite fixed income market declines, potential reporting lags, and the competitive environment in Asset Servicing. He also sought clarification on the NIB outlook.
CFO Dermot McDonogh expressed confidence in Asset Servicing's competitive strength, citing strong new business momentum and investments in infrastructure. He clarified the NIB outlook of $44-$46 billion was for the full year 2025. CEO Robin Vince added that there is not a significant lag in AUCA reporting.
David Smith of Pickering Energy Partners sought clarification on the sharply lower implied Q4 CapEx guidance and asked how the $50-75 million cost savings target relates to the SG&A performance already seen in Q3.
CFO J. Kevin Vann confirmed the low Q4 CapEx figure is correct, as spending was heavily front-loaded in fiscal 2025. On cost savings, he explained that while the Q3 SG&A of $66 million reflects some progress, the full $50 million run-rate savings is targeted to be fully effective at the start of fiscal 2026. He expressed confidence in achieving the $50 million and believes the full $50-75 million range is achievable.
David Smith of Pickering Energy Partners asked for clarification on the implied decrease in SG&A expenses for the second half of the fiscal year and inquired about the expected future run rate, including all contemplated synergies.
SVP and CFO Kevin Vann projected a full-year fiscal 2026 run-rate savings of $50 million to $75 million, primarily from G&A reductions and other permanent cost cuts. He confirmed that this synergy estimate does not include savings from lower costs on suspended rigs.
David Smith asked for details on the drivers behind the KCA Deutag (KCAD) international onshore margin guidance and the reasons for the difference between the forward outlook and KCAD's historical performance in calendar Q3 2024.
SVP and CFO Kevin Vann explained the guidance range reflects general market softness, the partial-quarter impact from the acquisition's closing date, and ongoing cost management for suspended rigs. Vann stated the vast majority of the performance decline from calendar Q3 2024 is due to Saudi rig suspensions, which represent an approximate $80 million negative impact on a full-year run-rate basis.
David Smith from Pickering Energy Partners asked about Seadrill's capital investment strategy for idle assets, specifically whether the company would start the Special Periodic Survey (SPS) for the West Gemini without a contract. He also sought commentary on why operators are locking in long-lead-time contracts despite near-term market softness.
President & CEO Simon Johnson confirmed that Seadrill is reluctant to commit discretionary capital for an SPS without a firm contract in place. Regarding long-lead-time contracts, Mr. Johnson stated that while operators likely see a future advantage, Seadrill is cautious about locking in 'long and low' rates, viewing its near-term market exposure as operating leverage. EVP & CCO Samir Ali added that Seadrill's focus is on minimizing idle time in 2025 while securing strong near-term rates.
David Smith inquired about the industry trend towards performance-based contracts, prompted by a competitor's recent deal, and asked if this is pressuring base day rates. He also asked a follow-up question about the stacking and reactivation costs for the West Capella rig.
Grant Creed, an executive, clarified that performance-based contracts are not a new concept for Seadrill and that the company is open to them for the right client and rig, citing the West Vela's high efficiency as a prime example. Regarding the West Capella, executive Simon Johnson explained that the rig is in a dynamic cost ramp-down phase as they still pursue opportunities, so a steady-state stacking cost has not yet been reached and will be updated in the next quarter.
David Smith asked for details on the West Tellus's 50 days of downtime in Brazil and sought confirmation and context regarding the $213 million litigation claim from Petrobras related to the historic Seche rig contracts.
President and CEO Simon Johnson confirmed the downtime was due to a stricter interpretation of existing regulations by the Brazilian regulator, not a change in rules. Regarding the litigation, he confirmed the $213 million claim amount, noted that contracts have penalty caps, and stated that Seadrill is in the early stages of evaluating its options and intends to vigorously defend its position.
David Smith inquired about the recontracting outlook for Seadrill's drillships in Brazil, specifically the Jupiter, Carina, and Tellus, and asked about the potential for upgrading 6th generation drillships to 7th generation capabilities.
President and CEO Simon Johnson described Brazil as the most important and resilient deepwater market, stating that while there was no specific news, the company is making 'meaningful positive progress' and is optimistic due to its incumbent advantage. EVP and CCO Samir Ali added that they remain confident in their ability to recontract the rigs. Regarding upgrades, Simon Johnson noted the 6th vs. 7th gen distinction is somewhat arbitrary, while Samir Ali emphasized that the company will not invest in upgrades without a clear, monetizable return on capital, and their current 6th-gen rigs are well-positioned in markets that do not require the extra capabilities.
David Smith asked why operators are signing long-lead-time contracts despite near-term market softness, and whether aggressive bidding to fill contract gaps could depress overall market pricing.
President and CEO Robert Eifler agreed the dynamic is unusual, attributing it to a strong consensus view of a market upswing in late 2026 and 2027. He acknowledged that drillers will likely offer discounts for short-term 'gap filler' work but believes this is 'noise' that will not affect pricing for longer-term contracts, as the entire industry anticipates future market strength.
David Smith asked about the new performance-based contracts with Shell and TotalEnergies, questioning if Noble's experience in Guyana informed its willingness to accept rate risk and if such structures are limited to long-duration programs. He also inquired how the CEA index pricing mechanism would account for the variable rate component.
President and CEO Robert Eifler confirmed that these strategic, performance-based contracts are a win-win but only work in select scenarios like long-term development programs. He noted that Noble's extensive internal performance data analysis provided the confidence to enter these agreements. Regarding the CEA index, Eifler explained the mechanism is flexible and designed to incorporate such nuances through a mutually agreed process, similar to how they internally forecast bonus achievement.
David Smith asked about the reasons for the contracting slowdown in the U.S. Gulf of Mexico and whether the low Q4 SG&A expense is a sustainable run rate.
President and CEO Robert Eifler attributed the U.S. Gulf slowdown to capital discipline among independents, noting this market can ramp down and up quickly. He contrasted this with West Africa, where he sees a more durable rebound in 2026. Regarding SG&A, management confirmed that Q4 is a decent baseline, reflecting the realization of about 50% of the Diamond acquisition synergies, with more to come in 2025.
David Smith from Pickering Energy Partners asked for an update on the outlook and current operating costs for the idle 'Developer' rig. He also followed up on the 'Globetrotter' rigs, inquiring if there is enough potential demand to keep both units working in 2025 and if they are expected to remain in the Gulf of Mexico.
President and CEO Robert Eifler grouped the 'Developer' with other similar rigs, seeing opportunities beginning in late 2025 and 2026. CFO Richard Barker specified the rig's current operating cost is approximately $100,000 per day. Regarding the Globetrotters, Mr. Barker confirmed there are active conversations for both rigs for work starting after H1 2025, with a higher focus in the U.S. Gulf, but noted the company would act decisively if it becomes a one-rig market.
David Smith sought confirmation of the Q3 adjusted EBITDA guidance range of $72 million to $76 million and asked for guardrails on the key moving parts. He specifically questioned if rental revenue would be roughly flat sequentially, excluding the contribution from the recent acquisition.
President, CEO & Director Joe Bob Edwards confirmed the Q3 guidance range and clarified that rental revenue will continue to increase, not be flat. He explained the near-term weakness is driven by an anticipated sequential decline in lower-margin product sales (VRU and compressor packages), while downhole component sales are expected to be flat. He reiterated confidence in achieving the previously guided low double-digit year-over-year EBITDA growth for the full year.
David Smith of Pickering Energy Partners sought confirmation of the Q3 adjusted EBITDA guidance of $72 million to $76 million and asked for details on the underlying assumptions, particularly regarding rental revenue versus product sales.
President & CEO Joe Bob Edwards confirmed the Q3 guidance range. He clarified that rental revenue is expected to continue to increase sequentially, while the primary headwind is an anticipated decline in lower-margin product sales of VRU and compressor packages. He noted that downhole component sales are expected to be flat. Edwards reiterated confidence in the full-year outlook for low double-digit EBITDA growth year-over-year on a pro forma adjusted basis.
Asked for confirmation of Q3 EBITDA guidance and clarification on the underlying drivers, particularly the expected performance of rental revenue versus product sales.
The company confirmed the Q3 guidance range. They clarified that rental revenue is expected to continue growing, while the weakness comes from product sales (packaged systems down ~10%, downhole components flat). They reiterated confidence in their full-year growth outlook.
David Smith asked if the expected mix of growth CapEx between business segments remains unchanged for the year and whether this spending outlook is supported by existing client activity, growing market share, or demand from new clients.
CFO Jonathan Byers confirmed that the growth CapEx allocation between segments is relatively unchanged, maintaining roughly a 60-40 split. CEO Joseph Edwards added that the spending is supported by 'a little bit of all of the above,' highlighting that customer conversations, particularly for the fast-growing VRU and HPGL product lines, remain consistent or slightly better than the previous quarter, driven by production focus and specific product advantages.
Asked if the growth CapEx allocation between segments remains unchanged, and whether the CapEx plan is supported by existing client activity, market share gains, or new customer demand.
The CFO confirmed the CapEx split between segments is unchanged. The CEO added that the CapEx plan is supported by strong customer conversations, particularly for VRU and HPGL, driven by a combination of consistent client activity, market share gains, and new demand fueled by favorable market dynamics.
David Smith asked about Flowco's perspective on M&A opportunities, given their history and current market valuations, and followed up on their comfort level with balance sheet leverage in the context of potential acquisitions.
CEO Joe Bob Edwards confirmed that M&A remains part of their strategy but stressed that the management team is highly disciplined and focused on 'returns accretive' deals, not just those that are accretive to earnings. He added that while they have ample liquidity, they will remain prudent with leverage and are not interested in testing the limits of their balance sheet.
Asked about the company's approach to M&A given market conditions and their comfort level with financial leverage.
M&A remains part of the company's strategy, but they will be highly disciplined, focusing only on returns-accretive deals with like-minded, technology-focused businesses. They are comfortable with their current balance sheet, have ample liquidity, and intend to remain prudent with leverage, emphasizing that they are not interested in testing the limits of their borrowing capacity.
David Smith of Pickering Energy Partners sought quantification for the Q3 utilization improvement, asked for color on the implied Q3 day rate decline, and requested details on the activity drivers behind the strong implied Q4 margin uplift.
SVP Wes Gotcher projected a utilization improvement of a 'few percentage points' for Q3 and confirmed the implied day rate softness is driven by expected weakness in the North Sea and West Africa, plus the absence of Q2's favorable FX impact. EVP & COO Piers Middleton cited Q4 strength from new subsea and drilling projects in Africa and Australia, while Gotcher added that a 50% reduction in drydock days would boost Q4 utilization by about three percentage points.
David Smith asked for the decision-making framework behind stacking a vessel versus keeping it active. He also confirmed the Q2 guidance and asked if the implied second-half margin improvement was driven by utilization or pricing.
CEO Quintin Kneen explained that the decision to stack is based on economic factors including regional opportunities, high maintenance costs, and potential for sale, particularly for the non-core vessels in question. Executive West Gotcher confirmed the Q2 guidance and stated the second-half margin uplift is primarily driven by better utilization, with some benefit from lower OpEx as dry docks decline.
David Smith of Pickering Energy Partners sought clarification on the 2025 drydock schedule, which seemed high, and inquired about the duration of new contracts and chartering strategy amid a softer market.
CFO Samuel Rubio attributed the 2025 drydock schedule to some project carryovers from 2024 and an increase in engine overhauls. Executive West Gotcher stated the average duration for new Q4 contracts was 12 months, while CCO Piers Middleton added that the strategy remains focused on shorter-term charters to capture expected market improvements in 2026-2027.
David Smith questioned the Q4 guidance, noting that flat revenue despite higher expected utilization implies a lower average day rate. He also asked about factors limiting the ability to move vessels from the weaker North Sea market to other regions.
Executive West Gotcher confirmed the inference, attributing the dynamic to rate pressure in the North Sea and project delays in the Americas and Asia Pacific. CCO Piers Middleton explained that vessel mobility is limited because specific drilling programs in regions like the Mediterranean require vessel specifications, such as large mud capacity, that many North Sea vessels lack.
David Smith from Pickering Energy Partners asked about the drivers behind the strong Q2 order intake and whether it signals a significant increase for 2025. He also inquired about opportunities for improved free cash flow conversion in a potentially flat 2026 activity environment, specifically around CapEx flexibility and working capital.
CEO Michael Jardon explained that the record Q2 orders were a result of both timing and a robust bidding environment, including significant contract renewals and extensions. Regarding 2026, both CEO Michael Jardon and CFO Sergio Maiworm confirmed a focus on improving free cash flow through continued margin expansion, cost-saving initiatives like Drive 25, new technology deployment, and flexing CapEx based on secured projects rather than speculation.
David Smith of Pickering Energy Partners asked about the drivers for the impressive Q2 order intake and whether it signals a sustainable trend for 2025. He also inquired about opportunities for improved free cash flow conversion in a potentially flat 2026, focusing on CapEx flexibility, working capital, and reduced one-off charges.
CEO Michael Jardon explained that the strong Q2 orders resulted from a combination of contract renewals, extensions, and favorable timing, supported by a robust ongoing bidding environment. Regarding 2026 free cash flow, both Jardon and CFO Sergio Maiworm highlighted that margin expansion would be driven by new technology adoption, acquisition synergies, and the 'Drive 25' cost-saving initiative. They also confirmed that CapEx is tied to specific projects and can be flexed accordingly, reinforcing a continued focus on margin and free cash flow growth.
David Smith of Pickering Energy Partners asked for clarification on the slightly lower full-year ROV utilization outlook, the drivers behind the ROV pricing uplift, and the company's visibility on the significant ramp in free cash flow expected in the second half of the year.
President and CEO Roderick Larson stated the lower ROV utilization outlook affects both rig and vessel support due to clearer Q4 visibility and confirmed pricing uplift is mainly from contract rollovers. SVP & CFO Alan Curtis addressed free cash flow, explaining that a strong second half is typical and the company has high visibility as much of it is already in receivables to be collected in Q3 and Q4.
David Smith from Pickering Energy Partners asked for clarification on the lower full-year ROV utilization outlook, the drivers behind the ROV pricing uplift, and the company's visibility into the significant free cash flow ramp expected in the second half of the year.
President and CEO Roderick Larson explained the lower ROV utilization outlook affects both rig and vessel support and is based on increased clarity on Q4 plans. He confirmed the pricing uplift is primarily driven by contract rollovers, not FX or performance-based pricing yet. SVP & CFO Alan Curtis addressed free cash flow, stating the second-half ramp is a typical seasonal pattern for the company and that they have strong visibility as a significant portion is already in accounts receivable.
David Smith of Pickering Energy Partners inquired if the slightly lower full-year ROV utilization outlook was related more to vessel or rig support. He also asked about the drivers of the ROV pricing uplift and sought clarity on the significant free cash flow ramp implied for the second half of the year.
President and CEO Roderick Larson explained the lower ROV utilization outlook affects both rig and vessel support and is based on increased clarity for Q4 activity. He confirmed the pricing uplift is primarily driven by contract rollovers at higher rates. SVP & CFO Alan Curtis addressed the cash flow question, stating the second-half ramp is a typical seasonal pattern for Oceaneering, with visibility supported by strong receivables from work already performed.
David Smith from Pickering Energy Partners asked for clarification on the lower full-year ROV utilization outlook, the primary drivers of the ROV pricing uplift, and the company's visibility on the expected second-half ramp in free cash flow.
President and CEO Roderick Larson stated the lower ROV utilization outlook affects both rig and vessel support and is based on clearer Q4 visibility. He confirmed pricing uplift is mainly from contract rollovers, not FX or performance-based deals yet. SVP & CFO Alan Curtis added that the second-half free cash flow ramp is a typical seasonal pattern, with high visibility due to a significant portion already sitting in receivables.
David Smith inquired about the growth strategy for the recently acquired GDi business and its potential to increase demand for Oceaneering's ROVs. He also asked for the Q1 ROV support mix and the drivers behind the full-year forecast for a higher mix of vessel-based activity.
President and CEO Roderick Larson explained that GDi's data-driven, predictive modeling technology can be deployed on ROVs for subsea infrastructure analysis, creating new demand for ROV dive hours. Larson confirmed the Q1 ROV mix was 62% drill support and 38% vessel-based, attributing the expected full-year shift toward vessel activity to versatile construction vessels serving energy and wind, increased OPG projects, and related tooling demand.
David Smith from Pickering Energy Partners questioned the drivers behind the strong Subsea Robotics (SSR) margin improvement, asking if it stemmed from lower operating expenses or contributions from tooling and survey. He also inquired about future tailwinds from remote piloting and how the defense AUV business would be segmented.
President and CEO Roderick Larson attributed the margin improvement primarily to operating efficiency gains and cost control within the ROV business, noting that higher utilization leads to fewer problems and a better operational rhythm. SVP and CFO Alan Curtis reinforced that ROV efficiency gains were a key driver. Larson added that remote piloting opportunities are expanding with better global 5G and satellite coverage. He clarified that the defense AUV business would be a manufacturing sale through the ADTech segment, though it could also involve operating the government-owned equipment.
David Smith from Pickering Energy Partners sought to reconcile the significant quarter-over-quarter decline in Well Intervention segment revenue and profitability, noting that operating days appeared to have increased.
CFO Erik Staffeldt clarified that Q2 results were impacted by a slower start in the shallow water segment and about 20 deferred mobilization days that pushed revenue into Q3. He also noted that the Q4000's Q1 utilization included 45 non-revenue transit days and that its work in Nigeria had a different rate structure with significant pass-throughs, skewing the per-day rate comparison between quarters. COO Scotty Sparks added the deferred mobilization days related to the Q5000, Q4000, and Well Enhancer.
David Smith questioned the long-term opportunities for the North Sea vessels, including their potential for work in other regions and the associated CapEx. He also asked about the Q4000's return to the U.S. Gulf from Nigeria and whether there is pricing pressure in the U.S. heavy well intervention market.
CEO Owen Kratz explained that redeploying the depth-limited North Sea vessels would require capital upgrades, a decision they are deferring while assessing the 2026 UK market. COO Scotty Sparks stated the Q4000 returned to the Gulf of Mexico for contracted work after its Africa project ended, aligning with their strategy to protect the GOM market. Sparks confirmed they are not currently seeing pricing pressure in the U.S. Gulf, with rates having stabilized.
David Smith of Pickering Energy Partners sought to clarify Helix's position amid concerns of a softening deepwater market, asking about contract coverage for heavy well intervention vessels in 2025-2026, the drivers behind the large 2025 EBITDA uplift guidance, and interest in the Q4000 in West Africa.
COO Scott Sparks confirmed that the heavy well intervention fleet is almost fully contracted for 2025 at improved rates, with significant commitments already in place for 2026. CFO Erik Staffeldt explained the $60-$100 million EBITDA increase for 2025 is driven by new contracts with approximately 40% higher rates in Brazil and 20% higher rates for the Q5000, with the range reflecting utilization variables. Sparks noted strong follow-on interest for the Q4000 in West Africa, which must be balanced against maintaining market share in the Gulf of Mexico.
David Smith asked about the 25 floater opportunities Valaris is tracking, specifically the proportion requiring 7th-generation drillships and the typical pricing premium over 6th-gen rigs. He also inquired about customer interest in performance-based bonus contracts and Valaris's strategy for balancing the associated risks and rewards.
President and CEO Anton Dibowitz, with additions from CCO Matt Lyne, explained that the vast majority of the 25 opportunities are for drillships, where customers show a clear preference for 7th-gen assets due to their efficiency benefits like higher hook loads and dual BOPs, especially for long-term programs. Regarding incentive-based contracts, Dibowitz stated that Valaris is open to these arrangements, which can be beneficial in long-term development drilling, but noted their complexity and does not expect them to become the universal standard.
David Smith of Pickering Energy Partners inquired about the demand for 7th generation drillships within Valaris's tracked floater opportunities and the pricing premium they command over 6th gen rigs. He also asked about the company's perspective on performance-based contract incentives.
President and CEO Anton Dibowitz stated that the overwhelming majority of the 25 tracked opportunities are for drillships, with customers preferring higher-spec 7th gen assets for their efficiency and optionality, especially on long-term projects. CCO Matt Lyne added that features like higher hook load and dual BOPs on 7th gen rigs offer significant cost savings to customers. Regarding performance bonuses, Dibowitz confirmed Valaris is open to such structures, which work best on long-term development programs, but noted they are complex to negotiate and not all customers prefer them.
David Smith asked for details on operating costs for idle rigs, the pace of cost reduction for warm-stacked units, and whether smaller exploration programs are also seeing delays similar to larger projects.
An executive, likely CFO Chris Weber, explained that warm-stacked drillship costs can be reduced to about $60,000/day over a three-month ramp-down period. CEO Anton Dibowitz added that smaller tieback and exploration programs are often 'second order' decisions for clients, their timing dependent on capital allocation after larger projects are funded.
David Smith inquired about the cost reduction details for warm-stacked rigs, including the timing, magnitude, and potential catch-up costs, and asked about the criteria for deciding to preservation stack a rig.
CEO Anton Dibowitz explained that warm stacking aims to reduce daily costs to the $60,000 range over about 90 days by cutting manning and fuel. He estimated reactivation costs at $5-$10 million. CCO Matt Lyne added specific targets of ~$60k/day for a drillship and ~$50k/day for a semi-submersible. Dibowitz noted that preservation stacking is only considered if there is no line of sight to work for approximately two years, which is not the current outlook given the strong pipeline for 2026.
David Smith asked for details on the cost reduction process for warm-stacked rigs, including the timing, magnitude, and potential catch-up costs upon reactivation. He also inquired about the criteria used to evaluate whether a rig should be preservation stacked instead.
President and CEO Anton Dibowitz explained that warm stacking involves reducing manning and fuel costs over a 90-day period, with reactivation costs estimated at $5-$10 million. He noted that preservation stacking is considered only when there is no line of sight to work for about two years. CCO Matt Lyne provided specific daily OpEx targets for warm-stacked rigs: approximately $60,000 for a drillship and $50,000 for a semi-submersible.
David Smith asked about the potential to accelerate value realization from the SANAD joint venture, possibly through an IPO, and requested more detail on the increased cost synergies from the Parker Wellbore acquisition.
Chairman, President & CEO Anthony Petrello stated that realizing SANAD's value is a paramount agenda item for both Nabors and Aramco, noting an IPO is an "obvious path" given attractive valuations in the region. CFO William Restrepo explained the increased Parker synergies stem from identifying greater overlap in corporate and overhead costs after gaining full access to the company's data post-acquisition.
David Smith asked for the company's current contracted volume coverage for the year. He also inquired about customer interest in signing longer-term contracts and how Atlas views the trade-off between securing longer duration versus pricing.
An executive stated that Atlas currently has approximately 22 million tons contracted for 2025 and expects that number to grow. Another executive noted a pull from customers for 100% supply agreements, adding that while longer-term deals may have slightly lower pricing, the trade-off is favorable due to the security of higher volumes.
David Smith asked about the commercial ramp-up cadence for the Dune Express, when it might reach its full run-rate, and how its margin profile might progress during the initial ramp-up period.
CEO John Turner projected the Dune Express would not be fully ramped until mid-2025. Executive Chris Scholla noted strong customer interest and a focus on seamlessly transitioning clients to the new system. CFO Blake McCarthy clarified that there is no introductory pricing; instead, the company is moving toward a single, fully delivered price for its sand and logistics services, with more detailed 2025 margin guidance to come.
David Smith of Pickering Energy Partners questioned whether geopolitical issues were causing an outsized impact on Q1 Reservoir Description margins and asked if the segment's strong 2024 incremental margins could be a good model for 2025.
Executive Lawrence Bruno confirmed that new sanctions announced in January had an immediate and significant negative effect on Q1 profitability and margins for the Reservoir Description segment. However, he agreed that the segment's historical incremental margin of nearly 60%, as seen in 2024, is a good framework for the rest of 2025, assuming revenue growth resumes.
David Smith of Pickering Energy Partners asked for Transocean's perspective on the decision process for stacking a rig, given its historical leadership in reducing industry capacity. He also inquired about specific metrics needed to begin returning cash to shareholders.
CEO Jeremy Thigpen stated that Transocean constantly evaluates its fleet and will scrap assets with a dim long-term outlook, viewing the current market as an opportune time for the industry to sideline lower-spec rigs. President & COO Keelan Adamson added that this high-grades the entire industry fleet. Regarding shareholder returns, Thigpen clarified that achieving a 3.5x net debt-to-EBITDA ratio is the key, hard-coded metric in their credit facility that must be met before distributions can be considered.
David Smith of Autonomous asked about the profitability timeline for newly recruited wealth management teams, specifically how long it takes for them to reach their run-rate contribution.
CEO and President Michael Roffler stated that new wealth management teams typically reach run-rate profitability relatively quickly, generally within a year to 18 months. He attributed this to the strong client relationships the teams bring with them and the additional benefit of new deposit relationships they generate for the bank.
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