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 klx.com. There'll also be a telephonic recorded replay available until March 26th, 2026, and 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 100 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 continue 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 continue to cut the suit to fit demand by aligning our footprint and cost structure with activity levels.

We reduced head count while protecting service quality, we maintained healthy metrics for revenue per rig and revenue per head count, 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 head count 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 accrual unwind, as well as impacts from our fleet refresh, asset rationalization, and other year-end items.

By segment, Northeast/Mid-Con 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 head count when comparing average Q4 2025 head count 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 to $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 under 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 31st, 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 two-thirds in cash and one-third in PIK.

We will evaluate future cash versus PIK decisions based on market conditions and company leverage and liquidity. As of the first 2 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 4.07 times versus a covenant of 4.5 times, and the covenant was scheduled to step down to 4.0 times at March 31st, 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 4.5 times through March 31st, 2027, resuming to the original step-downs as of June 30th of 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/Mid-Con 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 to $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 4 to 5 revenue days in many product service lines in certain districts. Looking forward to Q2 of 2026, we expect revenue to rebound to the $160 to $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 supports 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 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 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/Mid-Con was stronger, and your margins were much stronger than we were modeling.

Can you provide, and you covered this in the call, but I was hoping for a little bit more in color, particularly on the strength in Northeast/Mid-Con, which normally would expect to see some hit late in the year because of weather.

Good morning, Steve. Appreciate the question.

I think if you look at the segment as a whole, when you think about Mid-Con 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 exposure, as we referenced in the call, increased 5.3%, and 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. We saw a 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, but we saw the Mid-Con continue with completion programs through the year-end.

We continue to see wins in our accommodations business, our flowback business in East Texas. It held up exceptionally well.

Margin, of course, held up well, and look, we would forecast a slight decrease in revenue in that segment in Q1, predominantly tied to the previously discussed Winter Storm Fern, which really hit the Mid-Con pretty hard, but overall, we expect continued improvements throughout 2026. Then

the overall margin improvement, how much of that do you owe to product line mix versus efficiencies versus what clearly has been some cost reductions? Is it very much a mix, or would you weigh it more towards one or the other?

I think, and it's a great question. In the Northeast/Mid-Con specifically, I think it's

the first Broad-based, I guess, but

yeah. It's really lack of white space, really absorption of fixed costs, staying sustainably busy, and product line mix.

Helpful. Switching to the Southwest, when I look at that revenue line, was that primarily the impact on your completion product lines, and I'm assuming that continues at least through the first part of Q1?

It's a combination. We actually saw some reductions on the drilling side of the business.

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%, but yes, we did see some budget exhaustion in 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, so that attributed to some of the revenue decline.

Makes sense. That's helpful.

In terms of how you're thinking about CapEx and cash flows as we go into 2026, and knowing that we have markets that can move in different directions given the uncertainty that's out there, how are you thinking about CapEx and cash flows as we enter the year, knowing it can clearly change?

Look, the world is in turmoil, and we're not budgeting for increases, clearly. Our budget was set before the events of 11 days ago, 12 days ago really kicked off.

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've continued to spend to support the business.

We think that we'll continue to see some asset rationalization, DBR tools, lost in hole, etc., that'll drive net CapEx down into the $30 to $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 target just about the PIK option, how you're thinking about that, and then the covenant relief.

It looks typically you have very significant working capital seasonality, and typically 1Q 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 potentially put you at a closer point to where it was going to 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. This is Geoff Stanford.

Great question on that. The the waiver, we we, closing our books out, doing our year-end budget, going through the year-end audit, we're going through all these things at year-end.

We do look at stress testing of that. You look at certain hey, what ramifications if if this happens or that happens.

Going through that stress testing, we entered into it more as a proactive measure, give us some cushion for the future periods. Goes out 5 quarters or 15 months.

We we feel really good about that. Gives us gives us a lot of cushion there.

A lot of things happen in, as as you move forward. Working capital is one piece of that, but also as you as you stress test the model, what what does it what does it look like?

That that provided us a good proactive measure to to make sure we had cushion for future periods. That's that's the main the main reason that we entered into the in into the waiver, so.

As far as the the PIK option, your I think your first question on that, we did pick 33% of it in in Q4. We picked 75% in in January and February of of this year.

The the PIK option on on the on the note is is designed for flexibility. We utilize that flexibility as as as we see fit.

In this case, we we picked some, we pay some in cash, and and we look at it kind of throttle up and down as as we as we as we need to. Market dynamics, liquidity, leverage considerations, all taken into account into kind of our algorithm as as to how we want to do it, but that that's kind of what we did in the past, what we're doing the first 2 months of of of this year, so.

That's that's kind of how we look at the the the PIK option. We do like that flexibility, and and we use it we use it as needed,

so. Got it, that's helpful.

Chris, and 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? I know there's a lot of different outcomes, but just how you're looking at it on your business, what the potential outcomes could be?

It's a great question. Just one thing I want to clarify on the PIK, to Jeff's point.

Recall our leverage ratio includes capital lease balances as debt. That capital lease balance at year-end is going to amortize off pretty significantly this year.

There's an amount that you can pick 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.

Turning to your question, look, it's a great question regarding the Middle East conflict, and as we said at the outset, thoughts and prayers to the servicemen and women that are over there. If you think on a historical basis, Steve, we've typically seen a 60 to 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 to 60 days a material reduction in rig count post-Liberation Day with the tariffs and when commodity prices changed. I think what that speaks to is the cycles have gotten shorter.

That's for a couple of reasons. Operators don't have a lot of duration and tenor in their rig contracts today.

They're going pad to pad, well to well, etc. They react in much shorter time frames than they have historically.

We haven't really seen any reaction to $100 crude yet. We think most operators have taken a wait-and-see approach.

They just set their 2026 budgets, 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-plus in December of '26.

The strip and the tail of the strip is clearly much more conducive to Lower 48 activity. 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've benefited 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.

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.

As 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.

Appreciate it, Steve.

Thanks, Steve.

Thanks, Steve. This is Ken.

John Daniel, Chris, he had to drop, but he emailed me some questions. I'm going to read them to you

so

that way he'll hear them on the replay. "There continues to be a push by some operators to move to simul-frac operations.

Can you speak to your frac business and customer base and let us know what trends you're seeing?"

I think, look, a high-level perspective, specifically in the Mid-Con, 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 in a very material way with our frac rentals business, wellhead isolation business, etc.

That's not to say that the Mid-Con hasn't adopted simul-frac, but I think there's numerous reasons for the 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. If you, I would say on a stage-count basis, if you think about our forecast for this year, we're probably somewhere between 25 and 30% simul-frac, and and that's up year-over-year, but it's clearly not doesn't have the propensity that you would see in the Permian.

"Got it. 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 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 and incremental horsepower needs that some providers just aren't adept at managing either from a rate or pressure perspective.

A lot of providers are limited to 100 barrel a minute under 10k. 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 2 equipment. There was some horsepower that left the basin, but I think as you think about the basin today, it's amply supplied.

I don't think we're short horsepower by any stretch, and barring any material pickup in activity, back to Steve prior question around the Middle East situation, commodity prices, barring any material pickup in activity, I think John's probably optimistic that attrition's going to drive overall results. I think it's a pretty balanced basin today.

Okay. He's got a second topic of coiled tubing.

He says, "We've heard of at least one coiled tubing company suspending operations in recent months, and we believe some of those assets may be reconstituted by some other folks. At the same time, there are a very small number of units being built.

Thus, on the 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, and do you see the sector beginning to rationalize itself, or is that something you expect will occur in the next year or two, if at all?"

That's a broad question. I'll jump in on the first point.

We've definitely seen some attrition of units. We've seen over the last couple years one player exited the market about 2 years ago, and that equipment candidly vanished.

I aware of the player that John is talking about. 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.

I think the business is shaking out 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, WyCo, and so 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 pipe. 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 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, and so a provider has to have the expertise, the scale to manage all of the technologies required to complete 4-mile laterals with coiled tubing. That's multiple ERTs, coil connectors, string and fluid design.

They all have to be optimized. Risk 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 coil 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 commercial viable life of coiled tubing and expand the addressable wellbores.

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.