It is now my pleasure to introduce your host, Ken Dennard, Investor Relations. Thank you, sir. You may begin. Thank you, operator, and good morning, everyone. We appreciate you joining us for the KLX Energy Services conference call and webcast to review first quarter 2026 results. With me today are Chris Baker, President and Chief Executive Officer, and Geoff Stanford, Interim Chief Financial Officer. Following my remarks, management will provide commentary on its quarterly financial results and outlook before opening the call for your questions. There will be a replay of today's call that'll be available by webcast on the company's website at www.klx.com, and there will also be a telephonic recorded replay available until May 27th, 2026. More information on how to access these replay features was included in yesterday's earnings release. Please note that the information reported on this call speaks only as of today, May 13, 2026, and therefore, you are advised that time-sensitive information may no longer be accurate as of the time of any replay listening or transcript reading. Comments on this call will contain forward-looking statements within the meaning of the U.S. federal securities laws. These forward-looking statements reflect the current views of KLX management. Various risks and uncertainties and contingencies could cause actual results, performance, or achievements to differ materially from those expressed in the statements made by management. The listener or reader is encouraged to read the annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K to understand those certain risks, uncertainties, and contingencies. The comments today will also include certain non-GAAP financial measures. Additional details and reconciliations to the most directly comparable GAAP financial measures are included in the quarterly press release, which can be found on the KLX website. Now, with that behind me, I'd like to turn the call over to Chris Baker. Chris. Thank you, Ken, and good morning, everyone. I'll start with a brief overview of our first quarter results and recent trends across the portfolio, then l ater in the call, I'll discuss the current market backdrop and how we're thinking about the rest of 2026. Before getting into the numbers, I want to again recognize the men and women of the U.S. military who remain deployed in the Middle East. While the situation has evolved since our last call, it is far from re-resolved, and many service members and their families are still living with significant uncertainty. Nearly 100 KLX employees are veterans, and many more across our industry share that connection. On behalf of all of us at KLX, thank you for your service and sacrifice, and we continue to pray for your safe return home. Turning to the quarter, we expect Q1 to be the low point for the 2026 fiscal year, as it has been in prior fiscal years. The Q1 softness reflects the yearly pattern of customer budget resets and post-holiday restarts of completion programs, combined with specific scheduled disruptions caused by customer drilling issues delaying completion jobs and disruptions of approximately four to five days from Winter Storm Fern. Revenue was down sequentially in every product service line, or PSL, except for our tech services and accommodations businesses, which led to a negative shift in service offerings on a relative basis, with higher revenue contribution from drilling services relative to completion services. First quarter revenue was $145 million within our estimated revenue range, albeit at the lower end, primarily due to the previously mentioned Winter Storm Fern and customer delays in the last two weeks of March that pushed over $5 million of revenue into Q2 across multiple districts. Adjusted EBITDA for the quarter was $11.1 million, with an Adjusted EBITDA margin of about 8%, in line with the mid to high single-digit range historically delivered in Q1 and consistent with the context provided on our Q4 call. As in past years, margin reflected typical Q1 headwinds, seasonality, weather-related white space, and the payroll cost reset. Segment performance continued to reflect the shift in our portfolio towards gas-directed activity. The Northeast Mid-Continent segment again led the way with revenue up 28% year-over-year and Adjusted EBITDA of $10.9 million, almost 4x the first quarter of 2025 Adjusted EBITDA. Our dry gas revenue was up approximately 45% year-over-year, even though we did see a modest sequential decline of about 4%, the first sequential decline in five quarters, primarily tied to weather delays in the Haynesville. The Rockies and Southwest segments reflected a softer activity environment. The Rockies were pressured by typical winter seasonality and lower activity levels across several PSLs. We expect a meaningful sequential improvement in Q2 as we exit the worst of the winter impacts and currently forecast sequential improvements in all PSLs in the Rockies. In the Southwest, activity levels remain soft as the Permian rig count continued its decline in Q1, and operators slowed startup of some completion programs. Permian activity has shifted heading into Q2 with a sentiment shift around completions and DUCs in particular. Additionally, we see positive indicators for South Texas, which, along with expected activity rebounds in the Permian, should drive the Southwest. We continue to gain traction with larger blue-chip operators and are well-positioned as these operators increasingly demand certified higher spec equipment and stringent safety requirements. At the same time, we expect the second half of 2026 activity to benefit from smaller, independent and private operators driving incremental activity. Revenue per average operating rig was favorable year-over-year, landing at $273,000 in Q1 2026 compared to $269,000 in Q1 2025. The previously mentioned shift in revenues, however, contributed to a reduction in EBITDA per average operated rig of approximately 13%. Looking forward, based on our current Q2 revenue forecast, this metric will increase to above $310,000 in Q2, depending on Q2 average rig count, which is a level that has historically driven strong margins. With that, I'll hand the call over to Geoff to review our financial results in greater detail, and I will return later in the call to discuss our outlook. Geoff? Thanks, Chris. Good morning, everybody. Consistent with Chris's remarks, given the seasonality in our first quarter, particularly within the Rockies, the most useful analysis is a year-over-year comparison rather than a sequential comparison, so I'll discuss that accordingly. First quarter revenue was $145 million, down about 6% versus Q1 of 2025, compared with an estimated 12% decline in the average U.S. rig count. Adjusted EBITDA was $11.1 million or approximately an 8% Adjusted EBITDA margin, broadly consistent with the mid to high single-digit margin range we have delivered on prior first quarters. Net loss for the quarter was approximately $24 million or a loss of $1.23 per share. SG&A for the quarter was $15.4 million, down about 29% versus the prior year, reflecting the structural cost actions over the past several quarters. Turning to segment results. In the Rocky Mountain segment, first quarter revenue was $38.6 million, with an operating loss of about $3.8 million and an Adjusted EBITDA of roughly $2.1 million. Revenue declined approximately 19% year-over-year, reflecting lower activity across our product lines and typical winter impacts. As Chris previously mentioned, we expect Rocky's revenue and profitability to improve sequentially in Q2 as seasonal conditions normalize. In the Southwest region, first quarter revenue was $53.6 million, operating loss was $3.4 million, and Adjusted EBITDA was $4.6 million. Revenue declined roughly 18% versus the prior year quarter, driven by reduced oil-directed activity in the Permian that began at the beginning of Q2 of 2025. In the Northeast Mid-Con segment, first quarter revenue was $52.5 million, operating income was about $3 million, and Adjusted EBITDA was $10.9 million. Revenue increased 28% year-over-year, and Adjusted EBITDA quadrupled compared to Q1 of 2025, with segment Adjusted EBITDA margin expanding to approximately 21% from roughly 7% in the prior year period. This performance was driven by sustained gas-focused activity, particularly in our Haynesville and other Northeast Mid-Con operations, as well as strong execution and limited white space. At Corporate and o ther, Adjusted EBITDA loss was approximately $66.5 million in Q1, an improvement of about 11% year-over-year, reflecting ongoing G&A rightsizing and our focus on returning corporate costs towards 2021 and 2022 levels. Turning to capital allocation and cash flow. Capital expenditures in Q1 2026 were approximately $8.7 million, with net CapEx of roughly $5.3 million after about $3.4 million of asset sale proceeds. Spending was predominantly maintenance-oriented, focused on sustaining rentals, coiled tubing, through-tubing, pressure pumping assets. For the full year, we previously guided to approximately $40 million of gross CapEx and $30 million-$35 million of net CapEx. Based on the current purchase order logs and deployment schedules, our full year CapEx is tracking below that original framework. However, given the market backdrop and potential incremental activity, we expect to refine this range at mid-year. Net cash provided by operating activities was approximately $300,000 in the quarter. Unlevered free cash flow was - $1.4 million, and leveraged free cash flow was a - $5 million. As is typical for us, working capital was a use of cash in the first quarter, reflecting two additional payroll cycles in the period, an increase in Days Sales Outstanding, and lower accrued liabilities. We expect cash generation and liquidity to improve throughout the year, consistent with our historical seasonal pattern. Turning to the balance sheet. At quarter end, total debt was approximately $275.8 million, and total liquidity was $48 million, consisting of roughly $6 million of cash and cash equivalents and about $42 million of availability under our March 2026 ABL facility, including undrawn FILO capacity. Net working capital at quarter end was approximately $54 million. Given the significant revenue increase forecast in the second quarter, we expect a slight reduction in liquidity at Q2 close as working capital increases to support higher activity. With working capital levels expected to normalize over the second half of the year as receivables convert to cash and operations are funded from ongoing cash flow. With respect to our notes, consistent with the commentary we provided in our Q4 call, we paid 25% of interest in cash and 75% PIK for the first two months of the quarter, and we elected to PIK 100% in March. Looking forward, we expect to PIK interest 100% for Q2 and Q3 of 2026, and then go to a 50/50 ratio for Q4. We will continue to evaluate this mix based on market conditions, leverage, and liquidity. We remain well within our leverage covenants, providing us with incremental flexibility to fund CapEx, potential M&A, and other capital needs. With that, I'll hand it back over to Chris to discuss our outlook. Thanks, Geoff. From a macro standpoint, we continue to operate in a highly volatile but constructive environment. By all accounts, this is the largest energy shock in history. Commodity prices continue to be volatile and trade in a wide yet constructive band for activity due to the ongoing Middle East conflict and macroeconomic news. We're discussing customer reactions and expected incremental activity in real time, particularly in the Permian and other oil-weighted basins. I'd note, despite the recent declines in prompt month WTI pricing, the forward curve for the balance of 2026 is still constructive and operator sentiment seems to be shifting quickly. We have already seen larger operators accelerating DUCs and independent operators pulling forward activity in the face of elevated spot prices. On the gas side, the forward strip remains supportive, though as natural gas prices flirt with the mid $2 range, we have seen some operators feather the clutch a bit on activity, specifically in the Haynesville, with some considering pushing incremental programs to the second half of the year. We continue to believe that KLX's gas-weighted basins have longer-term strength, and KLX has meaningful exposure, particularly in the Northeast Mid-Con and Haynesville, to drive incremental revenue as activity increases. Looking forward, we are forecasting Q2 revenue of $162 million-$172 million with a midpoint of $167 million, 5% higher than Q2 of 2025 and $22 million higher than Q1 of 2026. We expect solid contributions from the Northeast Mid-Con and a seasonal rebound in the Rockies, with the Southwest gradually improving off of current levels as Permian activity stabilizes. We forecast revenue to increase in all three segments in Q2, along with nearly every single PSL. The mix of drilling versus completion versus production and intervention services will still lean unfavorable on a historical basis, but it is definitely trending back to normal. We expect Adjusted EBITDA margin to expand sequentially, driven by higher activity and better overhead absorption. Looking beyond Q2, our historic pattern has been for Q3 to be our strongest quarter of the year, and current operator commentary suggests a robust second half, particularly as smaller independents and private operators increase activity. Those customers have historically been a core customer base for KLX, and we look forward to seeing them increase their activity in the second half of 2026. That said, we wanna see how margins translate at higher revenue levels, including any impact from pricing and mix, before providing additional color on the second half of 2026 and updating our full year 2026 framework. In closing, I would like to thank our team of hardworking employees for their continued commitment and resilience, particularly given the challenges that always come with the first quarter in our business. I'd also like to thank our customers and shareholders for their ongoing support of KLX. We remain confident in our ability to execute our strategy and navigate what continues to be a dynamic and fast-moving market. With that, we'll now take your questions. Operator? Thank you. We will now be conducting a question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Thank you. Our first question comes from line of Steve Ferazani with Sidoti. Please proceed with your question. Morning, Chris. Morning, Geoff. Appreciate the detail on the call. Chris, when I think about the pretty significant sequential improvement guide you have in Q2, certainly it's much higher than we've seen the previous two years. I'm just trying to get a better sense of how severe the weather impact was to you on Q1 and how much that's leading towards the much stronger guide to Q2. Yeah, it's a great question. I think it very much depends on the region. You know, look, the Rockies saw typical seasonal winter weather as we always do, and we had a lot of non-operational days due to high winds, especially in North Dakota. We candidly don't and didn't quantify those days just due to the fact that this is a very typical seasonal pattern up there. I would say our gut feel is North Dakota and Wyoming this year were probably more impacted than last year. When you shift to the Mid-Con and Haynesville, we definitely, as we said in the prepared remarks, saw anywhere from two to five days of revenue loss across various PSLs. When you think about, you know, the combination collectively between Fern plus the drilling delays that we mentioned that pushed some completion programs out. We estimate approximately $5 million o f total revenue loss. As you well know, unfortunately, we still incur all the fixed costs, and candidly, on short-term notice, a lot of the variable cost in those instances, right? Okay. That's helpful. I was actually surprised at the sequential revenue improvement in the Southwest, given what activity has looked like there in Q1, but it was at a much lower margin. Can you sort of explain that? Yeah, sure. It's a great question. I think it was largely due to what we talked about in the prepared remarks, where we had a PSL mix shift that we referenced in the call with some completion activity slowing down, drilling activity holding in pretty well. It's puts and takes kind of across the board. I think we were also staffed up for some completions work that slipped later into the quarter, so that compressed margins as well. What I would say is we expect margins to expand in Q2. I think we'll continue, and we've already seen this in April, to see the mix shift improve as we'll see a reversal of what we saw in Q1. You know, on that point, just solely based off of internal April numbers, we've already seen them, you know, material. It's a one-month proxy, we've seen a material improvement in segment level margin in the Southwest relative to Q1. Got it. Excellent. You mentioned both of you mentioned in your remarks, typically it's the extra one or two payroll cycles in Q1. Usually, that's been your highest SG&A quarter. I was surprised how low SG&A was this quarter. What are you thinking about trends this year on SG&A after a very strong performance in Q1 in terms of how low it was? Yeah. Good morning, Steve. This is Geoff. I'll take that one. It was a good quarter for SG&A. We are looking obviously at every single dollar. We have a great team. We're looking at every single dollar. We're trying to keep those costs as low as possible without loss of quality. We're looking, you know. If you look at the full year, if you look at, you know, 2025, we did $68.5 million, 2024, $79.6 million. You know, our goal is to kinda get it into if we can get lower than 2025 for the full year is where we're heading. We're looking at it hard. It is a process going through it all, but we're definitely, you know, reviewing everything and going through that process. If you wanna think about SG&A for the full year, kinda think about it kind of the 25, maybe less than 25, rate. Excellent. That's helpful. Thanks, Geoff. You touched on this a little bit in your closing remarks. Chris, obviously, when we look at rig count, the one place we've continued to see growth was in the Haynesville, but obviously, we know lower natural gas prices could pressure there. Obviously, just even with the weather impact, still incredibly strong margin in that geographical region. Sounds like you're a little bit more cautious about growth moving forward, where you think the pickup maybe is in the oil basins for obvious reasons in the second half. Can you just walk through the different pieces there? Yes. It's definitely a multifaceted question. I think if you think about the pure Mid-Con, it's holding steady. The Haynesville has been the story of the year. It's up, what? eight rigs. Yeah Year-to-date and 25 rigs year-over-year. As we stated in our prepared remarks, we've seen a number of operators kinda feather the clutch, talk about holding back or delaying programs. Natural gas prices are still pretty robust if you look at the forward strip this morning. It's not but a couple months out where you start to see a three handle and then $4 later this year. I would say the second half of the year in the Haynesville kind of gets back on track from what I think is gonna be a little bit of a slow spell, if you will, in kind of the shoulder month of Q2. I think Q3, Q4 step up. Same thing for the Marcellus Utica. They're up two rigs year-to-date, kind of the same year-over-year. Q1 was seasonally very strong for us. When you think about all the components of the Northeast Mid-Con, the Northeast in that segment was very strong year-over-year, and I think the business there and the team continue to perform at an elevated and kinda steady pace, is the way I'd frame it. From a macro standpoint, there's no doubt D&C activity in that segment seems steady with, you know, some people talking about picking up rigs. The second portion of your question is, you know, what happens to oil demand and oil rig count the second half of the year. Look, it's a great question. This is the longest we've seen prices this elevated without a material inflection in rig count. Typically, 60-90 days after major moves in WTI, you'll see the market respond. That really hasn't been the case. Depending on if you're looking at Baker or Enverus rig counts, one kind of shows rig count year-to-date, the Permian almost flat, the other showing it slightly up. I think there's very nuanced reasons for the, you know, and part of that is the constant overhang of a Middle East deal and thoughts that prices would crash back to the $60 range on WTI. I think everybody's finally coming to terms that, even with some conclusion to the Middle East situation, WTI is not heading back below 70 anytime soon. In fact, the forward strip still has prices in the $80s in Q1 of next year as of this morning. In short, you know, it looks like based off of all indicators, operator discussions, public commentary by operators, the second half should tend to be stronger than the first half based off a number of macro tailwinds. It sounded in your prepared remarks, you were talking about the smaller independents and private operators potentially being the driver. Are you seeing any of that right now? Well, unfortunately, there are not as many of them around as there used to be, right? That's true. From a sponsor-backed entity standpoint, it's due to the wave of consolidation. We have seen some of those former teams PIK up some acreage around the margin, and we've seen some operators on the independent side do some pretty interesting acreage deals. We've definitely seen in the Permian and other basins some of the smaller operators kind of pull forward activity, especially completion activity, and accelerate the pace of drill outs, putting two coil units per pad. A lot of the smaller operators don't do that in the same way the larger operators typically do. We've seen more and more of that as we enter Q2. That basically is just pulling forward our existing base load of revenue anyway. The question becomes: how much incremental capital do they allocate on the year to increase drilling and completion expenditures? You have to think they're salivating at molecules at, you know, $90 a barrel, right? Right. Thanks, Chris. Thanks, Geoff. Yeah, appreciate it, Steve. Thank you. Our next question comes from the line of Josh Jayne with Daniel Energy Partners. Please proceed with your question. Thanks. Good morning. First one, you talked through the different geographies, but in light of the commodity price moves year- to- date, maybe you could just talk about different sense of urgencies around different product lines and how you see demand in the back half of the year across your different business lines first. Yeah, it's a great question, of course, we're geographically and product line diverse when you think about the business of KLX. I think your question kind of, Josh, first of all, good morning, that ties into what Steve was just asking. If you think about our guide for Q2, we typically don't provide granular detail around the market movement. You know, from a segment perspective, I think we're gonna see the highest rebound in Q2 in the Rockies, but that's really due to the performance in Q1, right? I would estimate of the incremental upside revenue, probably 50% of that's coming from the Rockies ballpark, followed by the Southwest, which is probably 30%, and then the Mid-Cons, the balance. I think those numbers are skewed due to KLX's diversity. Second half of the year, I think the rate of change of those probably shifts back to the oiler basins, specifically in the Permian. We've seen South Texas ramp a lot of activity of late. We're also having a lot of conversations with operators and seeing incremental opportunity sets in the Bakken, the Uinta, et cetera. I think all of those basins in the second half of the year probably drive on a relative basis, drive any outside kind of market performance, relative to the gas basins, 'cause the gas basins are already seeing a lot of the leg up. And while I think there's tailwinds there, I don't think you see the order of magnitude and the growth in those basins. Okay, thanks. Thoughts on pricing, how you see it evolving over the balance of this year. Do you think it'll be more region-driven or will it be more product line-driven? Maybe just any anecdotes you could give would be helpful. Yeah, great question. I'll start with saying what we said most of the second half of 2025, pricing in most PSLs across the industry I think is pretty anemic. You saw a lot of the frac guys, rig guys, et cetera, all said that pricing didn't justify reactivations, right? I think that that sentiment's pretty consistent. I think as we entered 2026, the floor was basically established, and there was kind of only 1 direction to go. We candidly had selectively started to push price on certain PSLs, specifically in the basins that we talked about that ramped earlier, late Q4 and into Q1 of 2026. I think that was a very specific and targeted set of PSLs, when we drove and we were able to drive some incremental pricing there. From a go-forward perspective, you know, look, we've pushed through, I think, just like most people have, the standard fuel surcharges of late. We have definitely started having conversations that in order to add capacity on PSLs, especially the people-intensive PSLs, i.e. not rentals and things of that nature, but more people-intensive PSLs like coiled tubing, wireline, et cetera, we need to see price move. We'll see how the market develops, but I think that's kind of the macro theme as we think about our portfolio. Thanks for that. Last one from me. Just still a lot going on with tariffs, global logistics being disrupted. Maybe you could just talk through anything you're seeing today and how that may impact, you know, an activity ramp coming in the lower 48 and steps you're taking to help mitigate supply chain risk moving forward. Yeah, that's a great question. I think, you know, if you go back to the 2016 or 2020 COVID cycle, what we saw coming out of both of those cycles was the biggest issue were people. I think, you know, seeing what John has forecasted for the second half of the year on rig count, there are not a lot of hot stacked rigs available in the market. If you think about pulling DUCs forward and adding completion activity or adding refrac activity at the same time as trying to ramp rig count, I think people could be the biggest stumbling block. You know, from a tariff perspective, it feels like most of those issues have been alleviated over the last couple of years. There are some sensors and boards on the directional and downhole module side, et cetera, that still have issues at times. I think everybody's watching the OCTG market just to see if things start to get tighter there again. Pricing on tubulars had come down over the last, call it 18 months, and I think they've kinda found the floor. We're, we're definitely watching that market real- time. Understood. Thanks for taking my questions. Appreciate it. Yeah, appreciate it, Josh. Thank you. Mr. Baker, I'd like to turn the floor back over to you for closing comments. Thank you once again for joining us on this call and for your continued interest in KLX. We look forward to speaking with you again next quarter. Ladies and gentlemen, thank you for your participation. This does conclude today's teleconference. You may disconnect your lines and have a wonderful day.