Eddie Kim

Eddie Kim asked about the expected trajectory of day rates for top-tier drillships, specifically if they could return to mid-$400s levels in 2027 or 2028, and inquired about the conclusion of Petrobras blend and extend negotiations and their reflection in the 2026 guidance.

Answer

Simon Johnson, President and CEO, and Samir Ali, Executive Vice President and Chief Commercial Officer, indicated expectations for day rates to exceed mid-$400s, potentially in 2026, driven by increasing utilization and dependent on geography. Regarding Petrobras, Simon Johnson stated positive ongoing discussions but no control over timing, while Samir Ali confirmed that the 2026 guidance incorporates the best available information at the time of its formulation.

Eddie Kim of Barclays inquired whether Atlas Energy Solutions' new customer wins and increased share of wallet were fully reflected in the first-quarter volumes guidance or if those volumes would kick in later in the year. He also asked about E&P operators' second-half wait-and-see approach, their underlying oil price assumptions (mid-$50s WTI), and what oil price would trigger a volume reduction.

Answer

SVP and President of Power Tim Ondrak and CFO Blake McCarthy clarified that new customer wins are not fully reflected in Q1 volumes due to weather impacts, with a ramp expected in Q2 and Q3. Blake McCarthy and Tim Ondrak indicated that E&P budgets are based on $50-$55 WTI, and current activity reflects this, suggesting that sustained lower prices would be needed to trigger second-half volume reductions, as they are comfortable at current levels.

Eddie Kim inquired whether Atlas Energy Solutions' new customer wins and increased share of wallet are fully reflected in the first-quarter volumes guidance or if their impact will be seen later in the year, and also asked about E&P operators' budgeting assumptions for oil prices and what price point might trigger a reduction in second-half volumes.

Answer

SVP and President of Power Tim Ondrak and CFO Blake McCarthy clarified that new customer wins are not fully reflected in Q1 volumes (partially due to weather) but will kick in more significantly in Q2 and Q3, with Q2 volumes expected to step up from Q1. Blake McCarthy and Tim Ondrak stated that E&P budgets are currently based on $50-$55 WTI oil, and current activity reflects this, with operators taking a wait-and-see approach for the second half, implying that sustained lower prices could lead to volume reductions.

Eddie Kim of Barclays sought to understand the confidence level in the Q3 volume guidance, which seems strong given market weakness, and asked for early expectations on Q4 seasonality compared to prior years.

Answer

CFO Blake McCarthy expressed confidence in the Q3 guidance for mid-single-digit volume growth, attributing it to strong execution and maintaining a flat crew count while the market has declined. For Q4, he acknowledged the potential for a typical seasonal slowdown, possibly more pronounced this year, but noted it was too early for a definitive forecast, with potential offsets from new customer trials.

Eddie Kim asked for directional trends on Innovex's subsea product bookings, comparing 2025 to 2024 levels and projecting expectations for 2026 and 2027. He also questioned Innovex's confidence in its reduced manufacturing footprint, following the Eldridge facility exit, to support increased subsea product demand during an anticipated offshore activity recovery in 2027 and beyond.

Answer

CEO Adam Anderson indicated that aggregate subsea orders in 2025 were slightly down compared to 2024, but Q4 2025 and early Q1 2026 saw a significant influx of new projects in Asia Pacific and the Mediterranean. He expects 2026 order volume to be up nicely versus 2025, with benefits materializing in late 2026 and into 2027. Adam expressed high confidence that the reduced manufacturing footprint, post-Eldridge exit, is fully capable of supporting a substantial increase in global subsea business activity.

Eddie Kim questioned Innovex's confidence that its reduced manufacturing footprint, following the Eldridge facility exit, can adequately support an anticipated increase in subsea product demand during an offshore activity recovery in 2027 and beyond.

Answer

Adam Anderson, CEO, expressed high confidence that the reduced footprint can effectively serve the market, even with a substantial increase in global subsea business activity levels. He reiterated that the Eldridge facility, while excellent, was designed for a different market environment.

Eddie Kim inquired about the confidence in the offshore market inflection occurring in late 2026 and early 2027, and the risks of it being delayed. He also asked if the full-year guidance already accounts for potential earnings risks from the Petrobras blend-and-extend negotiations.

Answer

Keelan Adamson, President and CEO, and Roddie Mackenzie, Chief Commercial Officer of Transocean, expressed confidence based on customer conversations, increasing tender activity, and public commentary from E&P executives, noting a significant increase in multi-year program awards. Mr. Mackenzie clarified that the guidance represents their best estimate and does not include significant incremental upside from the Petrobras negotiations.

Eddie Kim (Barclays) inquired whether the full-year guidance already incorporates potential earnings risks from the ongoing Petrobras blend-and-extend negotiations, or if their conclusion would represent an incremental impact.

Answer

Roddie Mackenzie (Chief Commercial Officer, Transocean) stated that the guidance reflects their best guess based on current conversations and would not consider the conclusion of these negotiations as significant incremental upside. He added that the negotiations focus on cost reductions, optimization, and mutual waste reduction, aiming for more efficient revenue and significant extensions for their sixth-gen fleet. Keelan Adamson (President and CEO, Transocean) emphasized the value of continuity for performance and cash flow generation.

Eddie Kim from Barclays inquired about the expected trajectory of leading-edge day rates and the contracting outlook for the Proteus and Concorde drillships in the Gulf of Mexico.

Answer

President and CEO Keelan Adamson and EVP & CFO R. Thaddeus Vayda explained that while current rates reflect some market softness, they anticipate utilization to bottom out in the mid-80% range before recovering. They emphasized a disciplined approach to contracting, focusing on overall economic value rather than chasing long-term deals at a market trough. They expressed confidence that the high-specification Proteus and Concorde rigs would likely be extended in the Gulf of Mexico due to strong customer interest.

Eddie Kim inquired about the expected timing for the announcement of new contracts with 2026 start dates and whether dayrates might face pressure due to an increase in idle rigs.

Answer

EVP & Chief Commercial Officer Roddie Mackenzie stated that numerous long-term contract awards are expected throughout the second half of the year. He acknowledged potential near-term rate pressure for short-term work but expects rates for long-term contracts to remain similar to current levels, supported by a sharp increase in projected rig demand for 2027-2029. President & CEO Keelan Adamson added that the timing of bids and negotiations will create a mixed bag in the near term, but the long-term outlook for fleet utilization is strong.

Eddie Kim inquired about the potential for 7th generation drillship day rates to fall to the $350,000 range due to market whitespace and asked about Transocean's reactivation strategy for its three cold-stacked 7G rigs.

Answer

EVP and Chief Commercial Officer Roddie Mackenzie stated that a significant dip in day rates is unlikely, especially for high-spec units, as drillers will remain patient for longer-term contracts. CEO Jeremy Thigpen added that the company continuously evaluates its stacked rigs and will only proceed with a reactivation if the customer funds it with an acceptable return.

Eddie Kim of Morgan Stanley inquired about the day rate trajectory for 2025, asking if leading-edge rates might soften due to competitors' utilization headwinds. He also sought an outlook on how many of the nine remaining sidelined 7th-generation drillships could secure contracts next year.

Answer

CCO Roddie Mackenzie stated that Transocean's premium 1,400-ton class rigs are already achieving rates in the $520k range and he doesn't foresee a significant dip for commodity 7th-gen units, suggesting lower-spec assets may be retired. CFO Thad Vayda added this situation doesn't impact Transocean's fleet, which is mostly on long-term contracts. Regarding sidelined rigs, President & COO Keelan Adamson noted no rush to reactivate them, preferring to target the stronger 2026-2027 market. CEO Jeremy Thigpen estimated only one to three sidelined rigs industry-wide might be contracted in 2025.

Eddie Kim asked for a regional breakdown of the anticipated offshore activity inflection, identifying which regions are expected to drive recovery and which might lag into 2027.

Answer

CEO Mike Jardon highlighted the positive and robust outlook for Subsea Tree orders as a leading indicator for 2027. He expects South America and MENA to be strong, the US Gulf to be flattish in 2026 with potential for expanded investment in 2027, and West Africa to be a significant inflection point in 2027 and beyond. Asia Pacific is anticipated to be more of a laggard, with its recovery expected later in 2027.

Eddie Kim from Barclays asked about the market assumptions underpinning Expro's 2026 EBITDA guidance, particularly regarding commodity price sensitivity (Brent $60-$70 range) and potential upside or downside scenarios.

Answer

CEO Mike Jardon clarified that Expro's activity is based on current commodity prices, noting that deepwater projects have long investment cycles, making them less susceptible to short-term throttling. He sees potential upside in the latter half of 2026 but emphasized the company's focus on expanding margins and cash generation even if revenue remains flat or slightly declines. Kim also inquired about the offshore activity inflection and regional drivers for recovery. Jardon highlighted the positive Subsea Tree outlook as a leading indicator for 9-18 months out, expecting a more robust second half of 2026 and 2027. He projected the US Gulf to be flattish in 2026 with potential for 2027 growth, South America to be strong, and West Africa to be a key driver for a significant inflection in 2027 and beyond.

Eddie Kim from Barclays sought further insight into the anticipated softness in Expro's activity levels during the first half of 2026, questioning if factors beyond Asia-Pacific were contributing to this outlook. Kim also asked for directional guidance on 2026 EBITDA, considering the company's projections for flat to slightly lower revenue alongside continued margin expansion.

Answer

CEO Mike Jardon attributed the H1 2026 softness to early budget preparation stages, customer caution due to commodity pricing and geopolitical events, typical Q1 northern hemisphere winter seasonality, and the historical slow start of NOC customers. He reiterated the focus on operational efficiency and technology rollout. Regarding 2026 EBITDA, CEO Mike Jardon stated that while he would be 'very disappointed' if EBITDA margins didn't expand, the absolute EBITDA number should be 'similar' to 2025, with a strong focus on cash generation.

Eddie Kim sought clarification on the anticipated softness in Expro's activity levels during the first half of 2026, despite an expected increase in the second half, and whether this softness is primarily driven by Asia-Pacific or other factors. Kim also asked for directional guidance on Expro's 2026 EBITDA, considering the expectation of flat to slightly lower activity levels but continued margin expansion.

Answer

CEO Mike Jardon explained that the outlook is based on early budget discussions and customer sentiment, influenced by commodity pricing and geopolitical uncertainties. He cited typical Q1 seasonality in the northern hemisphere, slow starts from NOC customers, and softness in Asia-Pacific as contributing factors. Jardon indicated that it is fair to assume 2026 EBITDA numbers should be similar to 2025 levels, emphasizing the company's focus on expanding EBITDA margins and improving cash generation.

Eddie Kim from Barclays asked about the potential impact of offshore rig white space on Expro's business in the second half of the year. He also pointed out the sequential revenue decline in the subsea well access segment and asked for more color on the softness and its expected duration.

Answer

CEO Michael Jardon responded that the company's forecast already incorporates rig movements based on detailed, bottoms-up customer engagement, though he noted some customer caution on short-cycle OpEx activity. Regarding the subsea segment, he attributed the Q2 softness to project timing, not a sustained issue, and stated that he expects a particularly strong rebound for that business in the fourth quarter.

Eddie Kim of Barclays asked about the potential impact of offshore rig 'white space' on Expro's business in the second half of the year, noting other service companies have cited it. He also questioned the sequential revenue decline in the subsea well access segment and its outlook.

Answer

CEO Michael Jardon responded that Expro's forecast already incorporates rig scheduling changes, based on detailed, bottoms-up discussions with customers. He noted more caution from customers on short-cycle intervention activity rather than long-term projects. Regarding the subsea segment, Jardon attributed the Q2 revenue dip to project timing, not a sustained trend, and stated he expects a particularly strong Q4 for that business line.

Eddie Kim asked if the portfolio approach leads to more content for TechnipFMC and if this approach will be adopted by more companies beyond a few majors. He also sought insight into what 'inning' operators are in regarding the shift of capital to offshore.

Answer

Doug Pferdehirt, Chair and CEO, TechnipFMC, confirmed that being both the architect and builder allows TechnipFMC to incorporate its technologies, creating opportunities. He stated the portfolio approach is applicable to any client with multiple greenfield developments in a regional area, not just majors. Based on customer behavior, he believes operators are in the very early stages of shifting capital to offshore, with a long runway ahead.

Eddie Kim asked if the portfolio approach leads to more content for TechnipFMC and if this approach will be adopted by more companies or remain limited to a few majors. He also inquired about the stage of operators shifting capital to offshore.

Answer

Doug Pferdehirt, Chair and CEO, TechnipFMC, confirmed that being both the architect and builder creates opportunities for TechnipFMC to incorporate its technologies, leading to more content. He stated that while not all clients have the asset base for multiple greenfield developments, the portfolio approach is applicable to any client with such opportunities. Based on customer behavior, he believes operators are in the very early stages of shifting capital to offshore, with a long runway ahead.

Eddie Kim of Barclays inquired whether the estimated $1.1 million per megawatt cost for ProPower's equipment changes for non-oil and gas applications like data centers, and if the equipment configuration differs for these end markets. He also asked if the incremental 450 MW needed to reach the 1 GW target by 2030 is expected to cost more than the current estimate, and how OEM pricing for power generation equipment has evolved over the past six months.

Answer

President of ProPower Travis Simmering clarified that the $1.1 million per megawatt estimate is for modular equipment suitable for certain power nodes in both oil and gas and data center markets. He noted that larger, more infrastructure-esque technologies for data centers might increase CapEx, but would require longer contract tenures and larger contract sizes to justify. For the incremental 450 MW, Mr. Simmering stated that ProPower is evaluating the mix and optionality, ensuring that return metrics remain consistent regardless of CapEx input, and that they are looking at the same return profile across different projects and industries.

Eddie Kim asked if the cost of ProPower equipment changes based on the end market, specifically if the $1.1 million per megawatt estimate increases when equipment is deployed for data centers. He also questioned whether the pricing environment for power generation equipment has changed, potentially leading to higher costs for the incremental 450 MW needed to reach the 1 GW target by 2030.

Answer

Travis Simmering, President of PROPWR, clarified that the $1.1 million per megawatt estimate is for modular equipment suitable for both oil and gas and data center markets. He noted that larger, more infrastructure-intensive technologies for data centers might increase CapEx but would require longer contract tenures and larger sizes to justify. Regarding future costs, Mr. Simmering stated that ProPetro is evaluating the mix for additional capacity and has optionality, emphasizing that return metrics will remain consistent regardless of CapEx input.

Eddie Kim questioned the outlook for Q4, asking for clarification on "normal seasonal patterns" and the potential for incremental softness. He also asked why ProPetro is confident in securing Pro Power contracts given the challenging market, and if power demand is independent of drilling activity.

Answer

CEO Sam Sledge clarified that the Q4 outlook is conservative, with "seasonality" referring to potential holiday downtime for the guided 10-11 active fleets. He explained that Pro Power's demand is resilient because it serves midstream and production customers, which is disconnected from the volatility of the completions market and is driven by long-term cost savings.

Eddie Kim asked about the day rate outlook for Tier 1 drillships, specifically if fixtures could reach the mid-$400,000s range in 2027 or if that's a 2028 event. He also inquired about the expected conclusion of Petrobras blend and extend negotiations and if these need to conclude before new contracts are awarded.

Answer

Robert Eifler (CEO) stated that reaching mid-$400,000s day rates in 2027 is a possibility, perhaps 50/50, but not yet the base case. He highlighted Noble's strong position for an inflection without day rate improvement due to its unique backlog curve. Regarding Petrobras, Mr. Eifler expressed hope for news in the next couple of months but acknowledged the complexity of their tender and negotiation dynamics, suggesting potential delays. He anticipates Petrobras rig numbers might decrease slightly, offset by other operators in Brazil.

Eddie Kim asked about the day rate outlook for Tier 1 drillships, specifically if mid-$400,000s per day could be seen in 2027 or if that's a 2028 event, and also inquired about ongoing negotiations with Petrobras.

Answer

Robert Eifler, CEO of Noble Corporation, stated that mid-$400,000s day rates in 2027 are a possibility, perhaps 50/50, but hard to predict. He highlighted Noble's strong position for an inflection without day rate improvement due to its unique backlog curve and staggered fleet contracting. Regarding Petrobras, Mr. Eifler hopes for news in the next couple of months, acknowledging Petrobras' complicated dynamics and expecting a slight reduction in their rig numbers to be offset by other operators in Brazil.

Eddie Kim asked for clarification on Noble's H1 2026 earnings and cash flow expectations relative to consensus, and the confidence level in the deepwater utilization recovery by late 2026/early 2027.

Answer

President and CEO Robert Eifler affirmed the directional narrative of lower H1 2026 results due to limited work, but anticipated a dramatic change in H2 2026. He expressed cautious optimism for the deepwater utilization recovery, citing existing contracts, market tightening, and ongoing negotiations, suggesting day rates have bottomed.

Eddie Kim asked for more detail on Noble Corporation's expectations for first half 2026 earnings and cash flow relative to consensus estimates, and sought clarification on the confidence level for the deepwater utilization recovery projected for late 2026/early 2027.

Answer

President and CEO Robert Eifler indicated that the first half of 2026 is expected to have limited upside for improvement due to less available work, with a dramatic change anticipated in the second half. He expressed cautious optimism about the deepwater utilization recovery by late 2026/early 2027, citing a combination of existing contracts, tenders, and customer conversations, suggesting day rates have likely bottomed.

Eddie Kim asked about the outlook for leading-edge day rates for the remainder of the year and whether there is a credible path for rates to return to the mid-to-high $400,000s in late 2026.

Answer

President and CEO Robert Eifler responded that day rates for Tier-1 rigs are holding in the low-to-mid $400,000s. While short-term 'gap filler' work might see lower rates, he doesn't expect a broader market decline given the strong outlook for late 2026. He affirmed there is a path for rates to increase with demand, but stressed that Noble is positioned for strong cash flow even in a flat market.

Eddie Kim asked for the rationale behind retiring the high-spec 7G drillship Meltem and questioned if competitors might follow suit, seeking an estimate on future 7G reactivations.

Answer

President and CEO Robert Eifler explained that the call on stacked capacity has been pushed out by at least 2-3 years, diminishing the rig's option value. He noted the Meltem had never drilled a well and would likely compete against Noble's own active fleet for shorter-term contracts. He believes a significant amount of active supply must be absorbed before stacked rigs are needed, making widespread reactivations unlikely in the near term.

Eddie Kim from Scotiabank questioned Noble's outlook for the first half of 2025, asking about the causes of rig utilization headwinds, or "white space," and the company's confidence in a demand rebound in late 2025 and 2026. He also inquired about the possibility of warm stacking a 7th generation drillship if market conditions do not improve.

Answer

President and CEO Robert Eifler acknowledged the white space in H1 2025, attributing it to a general lack of urgency from customers focused on capital discipline. However, he affirmed confidence in a late 2025/2026 recovery, citing a large volume of tenders, FID-ed projects, and a significant recent increase in customer conversations. Regarding rig stacking, Mr. Eifler stated that while the company will minimize costs on idle rigs, it would not take "dramatic measures" on a 7th generation rig that would render it less marketable.

Eddie Kim questioned Helmerich & Payne's perspective on the restrained North American market, particularly regarding competitor pricing strategies and the company's confidence in maintaining pricing discipline alongside an anticipated rig count ramp-up later in the year. He also asked about the sustainability of North American direct margins.

Answer

SVP of U.S. Land Operations Mike Lennox acknowledged a Q1 pullback from commodity-price-sensitive smaller E&Ps but expects a rebound in the back half of the year. He affirmed H&P's commitment to maintaining 45%-50% direct margins, prioritizing investment and customer outcomes over market share. For direct margins, Mike Lennox expects them to remain flat around $18,000 per day in the short term, with potential upside in the latter half of the year, supported by ongoing expense optimization.

Eddie Kim asked about the North American market, specifically if H&P is still encountering aggressive pricing from competitors and if the confidence in a full-year rig count ramp-up also applies to pricing stability or if pricing improvement will take longer to materialize. He also followed up on the sustainability of North American direct margins around $18,000 per day for the full year.

Answer

SVP of U.S. Land Operations Mike Lennox noted that while some smaller E&Ps are sensitive to commodity prices, H&P remains disciplined on pricing, targeting 45%-50% direct margins to support investments, and expressed optimism for a rig count pickup in the back half of the year. He indicated that North American direct margins are expected to remain flat around $18,000 per day in the short term, with potential for improvement in the back half of the year, also noting ongoing efforts to manage expenses.

Eddie Kim from Barclays sought a deeper breakdown of the full-year CapEx guidance, specifically asking for the amount of reactivation-related CapEx within the $230 million-$250 million maintenance and reactivation capital. He also questioned if reactivation-related OpEx would be a similar amount to the CapEx.

Answer

CFO Kevin Vann clarified that the $230 million-$250 million CapEx includes all rig reactivation costs, but an exact number per rig is difficult due to variability. He stated that there is more CapEx than OpEx hitting operating costs, with most margin impacts expected to clear in fiscal Q1, potentially bleeding into Q2. He reiterated that Q4 international margins were a low point, with expected improvement.

Eddie Kim from Barclays requested a deeper breakdown of the full-year CapEx guidance, specifically the portion allocated to reactivation-related CapEx versus maintenance, and whether reactivation-related OpEx would be a similar amount.

Answer

CFO Kevin Vann clarified that the $230 million-$250 million CapEx includes all rig reactivation costs, but an exact per-rig number is difficult due to variability. He stated that there is more CapEx than OpEx related to reactivations, with most OpEx impacts expected to clear in Q1 and Q2 fiscal 2026.

Eddie Kim from Barclays questioned the drivers behind H&P's relative outperformance in its Lower 48 rig count guidance and inquired about the activity dynamics between oil and gas basins.

Answer

SVP Michael Lennox attributed the resilient rig count to a strong customer mix and prior investments in rigs capable of drilling complex, long-lateral wells. He confirmed a slight pullback in oil plays has been offset by an uptick in natural gas plays like the Haynesville and Marcellus. CEO John Lindsay added that this aligns with a broader global trend toward natural gas.

Eddie Kim with Barclays sought clarification on the Q1 2026 completion services gross profit guidance, specifically whether the expected 14% sequential decline implied a significant pricing decline or was primarily activity-related. He also asked about the growth ramp-up for the new Saudi manufacturing facility for drill bits and its capacity to meet regional demand.

Answer

Andy Hendricks, President and CEO, clarified that the Q1 gross profit decline was primarily activity-related due to winter weather, pushing revenue into Q2, and not a significant pricing decline. He stated that any average price decline was in the single digits. For Saudi Arabia, Mr. Hendricks expects increased drill bit demand as rig counts rise, with the new manufacturing facility (which produced its first bit in December) meeting some of this need, supplemented by U.S. shipments until manufacturing expands.

Eddie Kim inquired about the completion services Q1 gross profit guide ($95 million, 14% sequential decline), asking if it implies a significant pricing decline or a headwind for the year. He also asked about the growth ramp-up for the new Saudi drill bit manufacturing facility, expected demand absorption, and regional export opportunities.

Answer

Andy Hendricks, President and CEO, clarified that the Q1 gross profit decline is primarily due to winter weather-related activity disruptions, pushing revenue into Q2, not a significant pricing decline. He stated that any average pricing decline is in the single digits. Regarding Saudi, Mr. Hendricks expects increased rig count to drive drill bit demand, with the new facility meeting some needs, supplemented by U.S. shipments, and potential for regional exports as manufacturing expands.

Eddie Kim of Barclays asked if the recent decline in the oil-directed rig count would negatively impact the Completion Services business in Q4, potentially leading to a steeper-than-normal seasonal decline. He also questioned the company's capital allocation priorities between bolt-on acquisitions and organic technology investments.

Answer

President & CEO William Hendricks responded that the rig count decline has disproportionately affected lower-technology rigs and smaller operators, to which PTEN has less exposure. He expects some seasonal softening in Q4 but is not certain it will be a steep decline. On capital allocation, he emphasized a focus on organic technology growth and share repurchases, while also noting the success of the Ultera acquisition and potential for further investment in downhole solutions.

Eddie Kim asked about the primary end markets for Liberty Energy's power generation equipment, specifically if the majority of the incremental 2 GW by 2029 would be for data center operators, and inquired if expectations for pricing and payback periods (5-6 years) for longer-term opportunities had changed.

Answer

CEO Ron Gusek confirmed that data centers now represent the largest percentage of LPI's projects, shifting from earlier expectations of primarily CNI and oilfield electrification, though those opportunities are still pursued. He reiterated that expectations for a 5-6 year payback and high-teens unlevered returns remain unchanged.

Eddie Kim with Barclays inquired about expectations for pricing and payback periods (5-6 year payback, high teens unlevered returns) for longer-term power generation opportunities.

Answer

CEO Ron Gusek confirmed no changes to these expectations, stating that a 5-6 year payback and high teens unlevered returns are still considered very reasonable.

Eddie Kim asked for clarification on the 600 MW incremental capacity, specifically how much is secured/ordered versus in advanced discussions, and Liberty's confidence in delivering 1 GW by end of 2027 given OEM sell-outs. He also requested an update on the Oklo equity stake and collaboration.

Answer

CFO Michael Stock expressed high confidence in delivering the 1 GW by end of 2027 due to unique OEM relationships, confirming that the vast majority of the incremental 600 MW is ordered (referring to 'landed' capacity). Regarding Oklo, he referred to company filings for equity stake details, noted some monetization for power generation deposits, and highlighted that long-term power contracts with hyperscalers will likely include small modular nuclear. He mentioned hoping to see electrons from Oklo's national lab generator by early 2028.

Eddie Kim from Barclays asked for the rationale behind reducing fleet count and redeploying assets to simul-frac operations, questioning if it was driven by customers halting activity or by unsustainable pricing pressure. He also asked about the earliest potential revenue from the OCLO alliance.

Answer

CEO Ron Gusek attributed the fleet reduction to a combination of smaller operators pausing activity and 'unconstructive' pricing from competitors, which led Liberty to choose not to participate in certain work and instead reallocate resources to long-term partners. CFO Michael Stock projected that significant revenue from large data center projects, including those under the OCLO alliance, would likely begin in 2027, with nuclear-generated revenue following in the early 2030s.

Eddie Kim from Barclays asked about the differences between the new 400 MW of power equipment and the existing deployed units, and questioned the implied capital cost per megawatt for future deliveries.

Answer

CEO Ron Gusek clarified that the new equipment will be more stationary and skid-mounted, unlike the mobile units for frac, and will include larger-scale engines. He explained that the all-in capital cost is approximately $1.3 million to $1.4 million per megawatt, which includes not just the generator but also the entire balance of plant (transformers, infrastructure, etc.), making it a fair estimate. CFO Michael Stock confirmed all 400 MW are already scheduled with manufacturers.

Eddie Kim of Barclays asked for an update on Mexico, inquiring about the operational outlook for Pemex, the confidence level in securing extensions for the five jackups with contracts ending in H1 2025, and the company's M&A strategy following its recent capital raise.

Answer

CCO Bruno Morand addressed the Mexico situation, stating the government's new $13 billion funding facility is a positive development that should enable activity to resume, and noted Borr Drilling is optimistic about securing new multi-year contracts. On M&A, CEO Patrick Schorn explained that while the time is right for consolidation, he could not provide specific details on targets but affirmed Borr's interest in rationalizing the market, similar to the Paragon acquisition.

Eddie Kim questioned the trend in leading-edge drillship dayrates, noting a recent dip to the low $400,000s, and asked about the potential timeline for reactivating one of Valaris's cold-stacked drillships.

Answer

SVP & CCO Matt Lyne and President & CEO Anton Dibowitz affirmed that while some rate pressure exists as utilization troughs in 2026, they expect rates to firm up as 7th-generation rig utilization recovers to over 90%. They highlighted recent fixtures in the $400k range as a sign of market resilience. Regarding cold-stacked rigs, Dibowitz stated the focus remains on contracting the active fleet, and they will be patient before reactivating assets.

Eddie Kim asked about the recent trend in leading-edge drillship dayrates, which appear to have softened into the low $400,000s, and whether further softening is possible. He also questioned the potential timing for reactivating a cold-stacked drillship.

Answer

CCO Matt Lyne stated that as 7th-gen utilization rises toward 90% by the end of 2026, dayrates should follow, but near-term fixtures will likely remain in the current band. CEO Anton Dibowitz reiterated that simple supply-demand economics are at play, with some pressure expected during the 2026 utilization trough. Regarding cold-stacked rigs, Dibowitz said the focus is on contracting the active fleet first, and the company will be patient before reactivating assets.

Eddie Kim asked about Valaris's full-year 2025 EBITDA guidance, seeking clarity on how much is already contracted versus dependent on new awards. He also inquired about the reactivation timeline for cold-stacked 7th Generation drillships.

Answer

CFO Chris Weber clarified that at the midpoint of the revenue guidance, approximately 94% is already contracted for the year. CEO Anton Dibowitz addressed the cold-stacked rigs, stating the focus is on the active fleet first and that the company will be patient, waiting for the right market conditions before reactivating these high-specification assets, without committing to a specific timeline.