Greetings, and welcome to the KLX Energy Services Fourth Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Ken Dennard. Thank you. Ken, 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 fourth quarter and full year 2025 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 a 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 klxenergy.com. There'll also be a telephonic recorded replay available until March 26th, 2026. Of course, there's more information on how to access these replay features that was in yesterday's earnings release. Please note that information reported on this call speaks only as of today, March 12th, 2026, and therefore you're advised that time-sensitive information may no longer be accurate as of the time of any replay, listening, or transcript reading. Also, comments on this call will contain forward-looking statements within the meaning of the United States federal securities laws. These forward-looking statements reflect the current views of KLX management. However, 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 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 also 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. Before we discuss our results, I would like to take a moment to say our thoughts and prayers are with all of the military personnel serving in the Middle East in the midst of this significant conflict. KLX has very close ties to our military. There are almost a hundred veterans that work for KLX and so many other veterans and their family members in the broader oilfield services space that we are all connected in some way. Again, our thoughts and prayers to all of our men and women in the military for a safe return. We sincerely thank you for your service. Now for our 2025 performance. 2025 was another solid year for KLX despite a choppy market, and we finished the year on a high note. The fourth quarter delivered our strongest profitability of the year with adjusted EBITDA and adjusted EBITDA margin both at 2025 highs. Throughout 2025, we continued to optimize our corporate cost structure and thoughtfully invested in our product lines while leaning into gas-weighted asset allocation as we realigned certain product service lines and benefited from capacity rationalization in the industry. KLX continues to execute against the playbook that we've outlined on prior calls. We focus on higher margin, technically differentiated work, lean into cost discipline, and are very intentional and diligent about where we strategically deploy capital and people. Operationally, the Northeast Mid-Con segment was the standout in the quarter. Despite typical winter weather and year-end budget dynamics, that segment held revenue essentially flat sequentially and again expanded margins driven by robust demand in our gas-directed work. Our dry gas exposure continued to grow as a share of the portfolio, and gas-levered revenue has steadily been marching back toward prior cycle peaks. In fact, dry gas revenue in this segment increased 5.3% quarter-over-quarter and 44% when you compare Q4 of 2025 versus Q4 of 2024, with broad-based gains across most of the product service lines we operate in this segment. On the other side of the ledger, the Rockies and Southwest reflected the realities of the macro environment. The Rockies were impacted by severe weather and customer budget exhaustion late in the year, and the Southwest experienced lower activity on reduced oil-directed rigs in the Permian. Even in that backdrop, Southwest margins expanded as we optimized our product and service mix, which is exactly the kind of blocking and tackling that is firmly within our control. Across the business, we continued to cut the suit to fit demand by aligning our footprint and cost structure with activity levels. We reduced headcount while protecting service quality. We maintained healthy metrics for revenue per rig and revenue per headcount, and we drove a meaningful reduction in our corporate cost year-over-year. Our efficiency metrics remained solid. In Q4, revenue per rig was approximately $297,000, the second highest quarter of the year, and we delivered more than $40,000 of EBITDA per rig for the second time in 2025. Revenue per headcount also held up well, consistent with our focus on aligning staffing with activity. I would like to take this time to personally thank everyone at KLX for their hard work, dedication, and persistence, which allowed us to achieve the above results in an admittedly challenging macro environment. Our employees' commitment to safe, efficient and quality work performance is what drives KLX and is the basis of the strong customer relationships that help us stand out from competitors. With that overview, I'll now turn 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. Starting with the fourth quarter, we generated revenues of approximately $157 million, which was in line with our Q4 guidance. As expected, revenues decreased due to seasonality and budget exhaustion. We generated approximately $23 million of adjusted EBITDA, our highest quarterly adjusted EBITDA of the year and an adjusted EBITDA margin of about 14%, also the high for 2025. The margin performance reflected favorable product line mix, ongoing cost reductions and normal fourth quarter approval unwind, as well as impacts from our fleet refresh, asset rationalization and other year-end items. By segment, Northeast MidCon revenue was essentially flat sequentially at $69.6 million, up about 0.5%, while delivering another quarter of adjusted EBITDA margin expansion to 25.3% and $15.1 million of total adjusted EBITDA, driven by gas-directed activity. Within that segment, dry gas revenue increased 5.3% quarter-over-quarter, continuing the trend of our gas-levered revenue base growing as a share of the portfolio. In the Rockies, revenues declined to $46.3 million, roughly 9% sequentially, primarily due to weather, seasonality and customer budget exhaustion. Adjusted EBITDA declined to $6.9 million or 15%. In the Southwest, revenue declined about 10% to $50.9 million from the third quarter, mostly tied to budget exhaustion and softer oil-directed activity in the Permian. Adjusted EBITDA increased to $6.8 million or 33%. On corporate costs, we made measurable progress. Corporate adjusted EBITDA loss improved to approximately $6.3 million in Q4, down from $6.6 million in Q3. For the full year, corporate adjusted EBITDA loss was around $26 million, bringing us back towards the 2021, 2022 levels. This reflects structural G&A rightsizing, including approximately 12% decline in total headcount when comparing average Q4 2025 headcount versus Q4 2024. Turning to capital allocation, net CapEx for 2025 was approximately $33 million. For 2026, we expect gross capital expenditures of approximately $40 million, down from $49 million in 2025, and net CapEx in the range of $30 million-$35 million, with the vast majority of that devoted to maintenance CapEx. Cash flow generation was strong in Q4, with cash provided by operating activities at $13 million, slightly lower than the $14 million in Q3 due to the aforementioned seasonality and budget exhaustion affecting the bottom line. Unlevered free cash flow was $15 million, a 43% increase over Q3. Total debt at year-end was $258.3 million, including $222.3 million in senior notes and $36 million in ABL borrowings, down from Q3 total of $259.2 million. We ended the year with available liquidity of approximately $56 million, including availability of approximately $50 million on the December 2025 asset-based revolving credit facility, borrowing base certificate, and approximately $6 million in cash and cash equivalents. Of note, due to the New Year's Eve holiday timing, December 31, 2025, we drew approximately $8 million in cash to fund the first payroll of 2026. From a balance sheet perspective, our capital lease obligations grew from their low point in Q2 of 2025 due to our previously discussed fleet refresh initiative, but will amortize down quickly through 2026, and we expect a meaningful lower capital lease balance at year-end. In addition, our coil leases roll off at the end of 2026, which will eliminate approximately $8.2 million of annual lease payments from our cash outflows beginning in 2027 and create incremental cash flow. During the fourth quarter, the company paid senior note interest expense 2/3 in cash and 1/3 in PIK. We will evaluate future cash versus PIK decisions based on market conditions and company leverage and liquidity. As of the first two months of 2026, the company paid 25% in cash and 75% in PIK. We were in compliance with all covenants under our senior notes. At year-end, our net leverage ratio was 4.07x versus a covenant of 4.5x, and the covenant was scheduled to step down to 4.0x at March 31, 2026. As we worked through the 10-K filing, stress testing for market risk indicated a potential need for covenant relief in future periods. We took the proactive step to amend the indenture and provide adequate cushion for the next five quarters. The amendment provides that the covenant will remain 4.5x through March 31, 2027, resuming to the original step downs as of June 30, 2027. The amendment also excludes capital lease balances from the leverage ratio calculation during the same period, affording us incremental flexibility to fund CapEx, M&A, and other capital needs. With that, I'll hand it back over to Chris for his concluding remarks. Thanks, Geoff. Let me start with the market backdrop and how we're thinking about 2026. We are approaching the year with a constructive but measured outlook. We expect the first quarter to be the low point for the year, reflecting the familiar seasonal combination of customer budget resets, slower restarts of completion programs, and weather-related disruptions. Beyond Q1, we see a path to a gradually improving market led by gas-directed basins, where we believe incremental rigs are more likely to show up before we see a more meaningful recovery in certain oil-directed markets. This, of course, is tenuous given the Middle East situation, and we will continue to monitor for oil-directed activity inflections. Our portfolio is increasingly aligned with that opportunity set. The Northeast MidCon and other gas-focused basins have been areas of momentum for us, and we expect them to remain important contributors as potential areas of growth on a relative basis. In oil-directed basins, particularly the Permian, we are managing through what has been a slow, extended downturn by rightsizing our footprint and cost structure to current demand while maintaining the flexibility to respond when conditions improve. Finally, in terms of how we're framing 2026 revenue, our internal budget contemplates a year that is broadly flat to slightly up versus 2025, with the majority of improvement weighted towards the second half of the year, yielding results that trend towards the stronger run rate we delivered in the second half of 2025. That framework will be updated as the year progresses and we gain more visibility into customer plans and basin-level activity. From a Q1 perspective, we're forecasting revenue of $145 million-$150 million, down approximately 3% from Q1 of 2025, despite rig count being down 8% over the same period. This forecast does include the impact of Winter Storm Fern, where we lost approximately four to five revenue days in many product service lines and certain districts. Looking forward to Q2 of 2026, we expect revenue to rebound to the $160 million-$170 million range, which is higher than Q2 of 2025. Industry consolidation and capacity rationalization remain important themes across the oilfield services landscape, and we believe KLX is well-positioned to be a net beneficiary. We've seen a number of smaller competitors exit the market in the last several months, which helped remove inefficient capacity and support a more rational competitive environment. On capital and fleet readiness, our philosophy has not changed. We continue to invest at a level that maintains our asset base and keeps us ready for a market inflection. At the same time, our capital program is disciplined and predominantly maintenance-oriented, which we believe strikes the right balance between prudence and preparedness in the current environment. With that, we will now take your questions. Operator? Thank you. We will now be conducting a question-and-answer session. If you'd 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'd 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. Our first question comes from Steve Ferazani with Sidoti & Company. Please proceed with your question. Morning, Chris. Morning, Geoff. Appreciate all the detail and color on the call. Two positive surprises, very similar to what you reported in 3Q in that, at least compared to our estimates, Northeast MidCon was stronger and your margins were much stronger than we were modeling. Can you provide? You covered this in the call. I was hoping for a little bit more in color, particularly on the strength in Northeast MidCon, which normally would expect to see some hit late in the year because of weather. Yeah. First of all, good morning, Steve. Appreciate the question. I think if you look at the segment as a whole, when you think about MidCon through Ark-La-Tex to the Northeast, is a pretty geographically diverse segment. But if you look at segment-level rig count aggregated, rig count increased about 6% across that entire segment in quarter-over-quarter. Just our dry gas exposures we referenced in the call increased 5.3%. Furthermore, to your question, I think all of the service lines held up exceptionally well. It's a continuation of the theme, and I think you asked a similar question last quarter. Yeah. We saw an early start in the Northeast last year that sustained through Q4, and we weren't sure how well it would sustain through November and December post-Thanksgiving because that is a very seasonally impacted business. We saw the MidCon continue with completion programs through the year-end. We continue to see wins in our accommodations business, our Flowback business in East Texas. Yeah, it held up exceptionally well. Margin, of course, held up well. You know, look, we would forecast a slight decrease in revenue in that segment in Q1- Yeah Predominantly tied to the previously discussed Winter Storm Fern, which really hit the MidCon pretty hard. Overall, we expect continued improvements throughout 2026. The overall margin improvement, how much of that do you owe to product line mix versus efficiencies versus, you know, what clearly has been some cost reductions? Is it very much a mix or would you weigh it more towards one or the other? Yeah, I think it's a great question. In the Northeast Midcon specifically, I think it's. Both, I guess, but yeah. Yeah. It's really lack of white space, really absorption of fixed costs, staying sustainably busy and product line mix. Yeah. Helpful. Switching to the Southwest. When I look at that revenue line, was that primarily the impact on your completion product lines? I'm assuming that continues at least through the first part of Q1. Yeah, it's a combination. We actually saw some reductions on the drilling side of the business. You know, rig count stayed pretty flat. I think it was up from a segment level when you combine all of the Southwest basins by about 2%. Yes, we did see some budget exhaustion and completion programs tailing off, going into the fourth quarter. Some of our PSL and asset realignment rotations that we referenced on the call were really pulling certain assets out of the Southwest segment, pushing them into the Haynesville. That attributes to some of the revenue decline. That makes sense. Okay, that's helpful. In terms of how you're thinking about CapEx and cash flow as we go into 2026 and knowing that we have, you know, markets that can move in different directions given the uncertainty that's out there, how are you thinking about CapEx and cash flow as we enter the year knowing it can clearly change? Yeah. Look, the world is in turmoil and, you know, we're not budgeting for increases. Clearly, our budget was set before the events of 11 days ago, 12 days ago, really kicked off. You know, we're targeting gross capital spending of $40 million. That's down from $49 million on a year-over-year basis in a year where we think revenue is flat to up. I think that speaks to, A, we don't have a lot of pent-up need for incremental CapEx in our business. We continue to spend to support the business, and we think that we'll continue to see some asset rationalization, DBR tools, lost-in-hole, et cetera, that'll drive net CapEx down into the $30 million-$35 million range. That is all subject to change based off of market inflections, but I think we're doing the appropriate level of spending and being prudent, so we're staged and ready to go for any market inflection. Got it. If I could talk just about the PIK option, how you're thinking about that, and then the covenant relief. It looks like typically you have very significant working capital seasonality, and typically one Q is your significant cash outflow. The covenant relief, is that primarily related to what we see as typically the working capital build in Q1, which would, you know, potentially put you at a closer point to where it was gonna step down to? How do you think about the relief now in your comfort level over the next few quarters? Hey. Hey, good morning, Steve Ferazani. It's Geoff Stanford. Great question on that. The waiver. You know, we closing our books out, doing our year-end budget, you know, going through the year-end audit, we're going through all these things at year-end. You know, we do look at stress testing of that. You look at certain case, some ramifications if this happens or that happens. Going through that stress testing, you know, we entered into it more as a proactive measure, give us, you know, some cushion for the future periods. It goes out five quarters or 15 months. We feel really good about that. Gives us a lot of cushion there. You know, a lot of things happen, and you know, as you move forward, you know, working capital is one piece of that, but also as you stress test the model, what does it look like? That provided us a good proactive measure to make sure we had cushion for future periods. That's the main reason that we entered into the waiver so. As far as the PIK option, I think your first question on that. Yeah. We did PIK 33% of it in Q4. We PIKed 75% in January and February of this year. You know, the PIK option on the note is designed for flexibility. We utilize that flexibility as we see fit. In this case, we PIK some, we pay some in cash, and we look at it kinda throttle up and down as we need to. Market dynamics, liquidity, leverage considerations, all taken into account into kind of our algorithms as how we wanna do it. That that's kinda what we did in the past, what we're doing the first two months of this year. That's kinda how we look at the PIK option. We do like that flexibility, and when we use it, we use it as needed. Yep. Got it. That's helpful. And Chris, I know it's way too early to really have an outlook on this, but what is your take on the potential impact from the Middle East conflict? If it's extended, if it's not, what do you think. I know there's a lot of different outcomes, but just how you're looking at it on your business and what the potential outcomes could be. Yeah, it's a great question. Just one thing I wanna clarify on the PIK to Geoff's point. Recall, our leverage ratio includes capital lease balances as debt. That capital lease balance at year-end is gonna amortize off pretty significantly this year. Yep. There's an amount that you can PIK where you can stay all else equal, basically net debt neutral, right? That's another consideration that we factor in when we think about overall leverage profile. But turning to your question, look, it's a great question regarding the Middle East conflict. As we said at the outset, you know, thoughts and prayers to the servicemen and women that are over there. If you think on a historical basis, Steve Ferazani, we've typically seen a 60-90 day lag in activity increases or decreases post-commodity prices moving. What we saw in April of last year was almost an immediate reaction, but we definitely saw kind of 45-60 days a material reduction in rig count post-Labor Day with the tariffs and when commodity prices changed. We have not seen. I think what that speaks to is the cycles have gotten shorter, and that's for a couple of reasons. Operators don't have a lot of duration and tenure in their rig contracts today. They're going pad to pad, well to well, et cetera. They react in much shorter time frames than they have historically. We haven't really seen any reaction to $100 crude yet, and we think most operators are taking a wait-and-see approach. They just set their 2026 budgets, you know, and so it's hard to say. What I will say is, as of this morning, the forward strip, you can do forward swaps at $72+ in December 2026. The strip and the tail of the strip is clearly much more conducive to lower 48 activity. You know, the other point would be, from a KLX perspective, we don't actually have to see incremental rig count to see increases in our own activity. If you think about our completion production intervention business line, we benefit from increases in refrac activity, workovers, well intervention, stimulation of existing wells. We've talked a lot over the last year about how the refrac market, specifically in the Bakken, to a lesser extent in the Eagle Ford, slowed down through 2025. You know, we're keeping our ear to the ground, trying to stay close to customers. We'll see how protracted the situation becomes, how much energy infrastructure in the Middle East is damaged and what happens to commodity prices, and I think specifically the tail over the next month. Yeah. As you know, we've got the right asset base, we've got the right technology and people. If customers elect to ramp activity, we will absolutely be there and be prepared to participate. That's great. Thanks, Chris. Thanks, Geoff. Yeah. Appreciate it, Steve. Thanks, Steve. Thanks, Steve. This is Ken. John Daniel, Chris, he had to drop, but he emailed me some questions, and I'm gonna read them to you. Okay. That way, he'll hear them on the replay. Fair enough. There continues to be a push by some operators to move to simul-frac. What is it? Simul-frac. Simul-frac operations. Can you speak to your frac business and customer base and let us know what trends you are seeing? Yeah, I think, look, a high-level perspective, specifically in the MidCon, is we haven't seen the huge adoption of simul-frac relative on the same pace that we've seen in other basins. We clearly are participating in simul-frac in the Permian and other basins in a very material way with our Frac Rentals business, Wellhead Isolation business, et cetera. You know, that's not to say that the MidCon hasn't adopted simul-frac, but I think there's numerous reasons for the slower adoption rate. One being the acreage profile, operator size in some instances, pad sizes, lack of electrical infrastructure, when you think about comparing to the large electric spreads in the Permian. We have seen some adoption. You know, I would say on a stage count basis, if you think about our forecast for this year, we're probably somewhere between 25%-30% simul-frac, and that's up year-over-year. But it's clearly not. It doesn't have the propensity that you would see in the Permian. If, and this is John's words, if not mistaken, that's not a basin that's seen a lot of new capacities in some years. Would it seem that attrition would be a little more pronounced, or is that too optimistic on his part? John's always optimistic. I think, look, tying back to the first part of the question, simul-frac definitely adds a layer of complexity in incremental horsepower needs that some providers just aren't adept at managing either from a rate or a pressure perspective. You know, a lot of providers are limited to 100 barrels a minute under 10-K. And so as you think about attrition within the basin, and I'm sure John's not on the call, I'm sure he's aware, the general industry said there was about 10 spreads sold last year to international locations. Most of those spreads were tier two equipment. There was some horsepower that left the basin. I think as you think about the basin today, it's amply supplied. I don't think we're short horsepower by any stretch. You know, barring any material pickup in activity, back to Steve Ferazani's prior question around the Middle East situation, commodity prices, I think John Daniel's probably optimistic that attrition is gonna drive overall results. I think it's a pretty balanced basin today. Okay. He's got a second topic of coiled tubing. So we've heard of at least one coiled tubing company suspending operations in recent months, and we believe some of those assets may reconstituted by some other folks. At the same time, there are a very small number of units being built, thus on one hand, there are those who have struggled and those who are doing well. Can you give us your thoughts on the U.S. coiled tubing market? Do you see the sector beginning to rationalize itself, or is that something you expect will occur over the next year or two, if at all? That's a broad question. I'll jump in on the first point. You know, we've definitely seen some attrition of units. We've seen over the last couple years, one player exited the market about two years ago, and that equipment candidly vanished. I'm aware of the player that John is talking about. You know, the majority of the optimal assets were reconstituted into and absorbed by a pretty sizable player in the business today. There were some assets that landed in a startup. We're aware of another situation that is currently active with another smaller player exiting the market altogether. You know, I think the business is shaking out, but for different market dynamics. If you think about the Bakken, that has shrunk as a coil market. We've seen players move equipment out of the Bakken, either back to Canada or down to the Permian and other basins, Waco. There's been a lot of coil decline in certain regions due to the length of the wellbores surpassing capacity of the units in those regions and the growth of snubbing and stick pipes. From pivoting to the second part of his question, from a new build perspective, look, John's correct. There's kind of very few new build units that are under construction and, you know, the ones that are solely focused on ultra-deep extended reach laterals. That's where the market is heading. The routine frac screenouts, wellbore cleanouts have become fewer and fewer. A provider has to have the expertise, the scale to manage all of the technologies required to complete 4-mi laterals with coil tubing. That's multiple ERTs, coil connectors, string and fluid design. They all have to be optimized. Risks are increased, pipe costs are increased, and operators are monitoring ROP, KPIs in real-time, and switching costs are candidly minimal as they're trying to think about the risk-reward and efficiency gains of coiled versus alternatives. Candidly, I think that's where KLX has an advantage with our in-house proprietary mud motors, our extended reach tools, as well as additional technologies that we're bringing to bear to extend the commercially viable life of coiled tubing and expand the addressable wellbores. Good. Operator. Okay, this concludes our Q&A session. I'd now like to turn the call back over to Chris Baker for final comments. Thank you once again for joining us on this call today and your continued interest in KLX. We look forward to speaking with you 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.