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Operator: Good day, ladies and gentlemen. Welcome to the NOV Fourth Quarter 2022 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. As a reminder, this conference call is being recorded. I would now like to introduce your host for today’s conference call, Mr. Blake McCarthy, Vice President of Corporate Development and Investor Relations. Sir, you may begin.

Blake McCarthy: Welcome, everyone, to NOV’s fourth quarter and full year 2022 earnings conference call. With me today are Clay Williams, our Chairman, President and CEO; and Jose Bayardo, our Senior Vice President and CFO. Before we begin, I would like to remind you that some of today’s comments are forward-looking statements within the meaning of the federal securities laws. They involve risks and uncertainty, and actual results may differ materially. No one should assume these forward-looking statements remain valid later in the quarter or later in the year. For a more detailed discussion of the major risk factors affecting our business, please refer to our latest forms 10-K and 10-Q filed with the Securities and Exchange Commission.

Our comments also include non-GAAP measures. Reconciliations to the nearest corresponding GAAP measures are in our earnings release available on our website. On a U.S. GAAP basis for the fourth quarter of 2022, NOV reported revenues of $2.07 billion and net income of $104 million. For the full year 2022, revenues were $7.24 billion and net income was $155 million. Our use of the term EBITDA throughout this morning’s call corresponds with the term adjusted EBITDA as defined in our earnings release. Later in the call, we will host a question-and-answer session. Please limit yourself to one question and one follow-up to permit more participation. Now, let me turn the call over to Clay.

Clay Williams: Thanks, Blake. For the fourth quarter of 2022, NOV’s revenues grew a solid 10% sequentially and fully diluted earnings were $0.26 per share. EBITDA increased to $231 million or 11.1% of revenue with sequential flow-through somewhat impacted by continuing supply chain challenges, incremental cost to expedite key orders and less desirable mix. Consolidated book-to-bill was 111% on 16% higher sequential shipments out of backlog. Compared to the fourth quarter of 2021, incremental EBITDA flow-through was 29% on a very strong 37% year-over-year revenue growth. For the full year 2022, NOV generated $679 million in EBITDA on $7.2 billion in revenue, which included $332 million in renewable energy-related revenue. Incremental flow-through was 26% on 31% year-over-year growth.

2022 was a good year for NOV, our team executed well in the face of continuing extraordinary challenges. We introduced new products that we developed through the downturn that improve the efficiency, safety and environmental impact of our customers’ operations, including several greenhouse gas emissions reducing technologies and an edge computing platform is the foundation for several new digital products. EBITDA marched up steadily quarter-by-quarter as revenue grew, and we benefited from the cost reductions of prior years. We push prices higher, more successfully in some product lines than in others. While EBITDA margins improved, frankly, we are disappointed in the magnitude of our price driven margin expansion so far. Our marketplace remains competitive, as our competitors seek to load plants after the pandemic lockdown decimated volumes.

But nevertheless, we have been successful in clawing back discounts and achieving significant pricing increases. However, the ramp in inflation we saw throughout the year has driven our costs up materially. While we still have ways to go, we are much, much closer to earning acceptable returns on capital, and it is early days in what we are confident will be an extended upcycle. For the world, 2022 was an eventful year in a string of eventful years. It was a year of learning about constraints. We learned that when economies reopen, after being closed for a pandemic, knock-on effects and unforeseen constraints are created which reverberate far into our future. We started the year hopeful that 2022 will see an end to the chaos of the pandemic and the wrecking ball that the economic shutdowns brought to our industry in 2020 and 2021.

Remember negative oil prices and the lowest rig counts on record, following hundreds of oil patch bankruptcies and downsizing that saw tens of thousands of years of valuable experience, leave the oil field. We were hopeful that 2022 would finally bring our industry a respite to heal and rebuild. Unfortunately, the fragility of our energy situation blew up on us with the outbreak of hostilities in Ukraine, which spiked energy prices and prompted renewed urgency and oilfield recovery. That’s what exposed the manning obstacle course of constraints, through which the industry must navigate in order to ramp production. The industry’s constraints underpin our long-term bullish outlook. We foresee further growth ahead in demand for NOV’s products and services for the next several years, but we also see some near-term challenges, as more healing and rebuilding is needed.

The downturn eroded a great deal of offshore drilling capacity. Many desperate offshore drilling contractors cut maintenance to preserve cash, laid-off experienced workers and cold stacked rigs. Collectively, the industry scrapped 386 offshore drilling rigs since 2011. Sadly, it didn’t work. Almost all offshore drilling contractors still went through bankruptcy, and many today are owned by frustrated ex-bondholders forced to become equity owners. They want their money back and the sooner the better. So, when E&P companies eyeing higher commodity prices decided to reenter the offshore drilling market to finally develop their blocks after an absence of several years, they discovered in mass what a daunting challenge we faced to restart long idled offshore drilling assets, particularly when the asset owners have limited capital and limited appetite to invest in.

There is seemingly no lack of demand for these assets. Rising development activity in Brazil and West Africa, new basin development in Guyana, shallow water activity in Mexico, the Arabian Gulf and India, brownfield tiebacks in the Gulf of Mexico and the North Sea, and promising expiration areas emerging in Namibia, Suriname, and the Eastern Mediterranean present a great deal of offshore drilling need. There’s plenty of demand for years to come, but right now there are two constraints, money and supply chain. The freshly restructured offshore drilling contractor industry has little access to or appetite for external capital to rebuild itself. Despite 30% headline project cost increases since 2020, E&Ps are becoming more confident in their economics in the energy security challenged new reality we are living in.

But they’re finding one more cost that they need to dial in, and that’s a way to finance the refurbishment of offshore drilling rigs through higher day rates and mobilization fees. National oil companies and integrated majors supplemented by shipyards offering bareboat charters and importantly eastern hemisphere sovereign wealth funds are the emerging sources of capital that we foresee underwriting the big offshore drilling restart. The second constraint is supply-chain, broadly. COVID-driven workforce disruptions, lack of critical components, and expensive unreliable freight have injected new execution risk into all shipyard projects in Asia and elsewhere, and not just for offshore rigs, FPSOs also face higher execution costs and risks as we hear from our Completion & Production Solutions customers.

Despite these challenges, our Rig Technologies teams successfully completed 15 offshore rig reactivation projects in the fourth quarter, mostly jack-ups. And we are pleased to launch 23 new reactivation, recertification and upgrade projects on offshore rigs during the quarter. We’re seeing rising interest in more floater activity, which is not surprising with drill ship day rates squarely in the mid $400,000 per day range. While a long way from anything approaching new build economics, it is clear that high demand is driving the industry steadily towards recovery. Early projects are the bare minimum, but as industry demand rises and capital sources solidify, we expect customers to use the reactivation time spent in shipyards to upgrade with items like a second subsea BOP stack to comply with BSEE regulations for instance.

Rig Technologies revenues from the offshore grew 22% sequentially and Completion & Production Solutions revenues also grew 22% sequentially from offshore customers. Wellbore Technologies offshore revenues were up 5% as well, enabling NOV to post a consolidated 18% sequential increase from all its offshore customers. Turning to international land, for the first time in a dozen years, day rates and oilfield services pricing are on the rise. Unlike North America, most international land markets did not retool themselves up to higher levels of technology in the super cycle of 2004 to 2014. Phase 1 of the U.S. shale revolution was for the replacement of the land rig drilling fleet with higher capability AC rigs and the buildout and a fit for purpose frac-spreads.

International markets never took that step, relying instead on older technology and used equipment. That’s beginning to change in places like the Middle East and Argentina, where national oil companies are frustrated with materially lower efficiencies compared to North America. I’m pleased to report that the first two high spec rigs delivered by our new plant in Saudi Arabia are performing very well, and interest is growing from other land drilling contractors in the region. We also see rising demand for newer coiled tubing equipment as well as the directional drilling kit, bits and drilling motors that we offer in key international land markets. While Chinese competition in these markets can be fierce, these products offerings are head and shoulders better, and national oil company bureaucracies are waking up to the idea of buying on value and service as opposed to strictly buying on price.

So to summarize, we are bullish on international land markets and offshore for 2023. Consolidated international land revenues increased 13% sequentially for NOV with all three segments showing strong growth. But now, let’s talk about North America. Our consolidated revenues from North America land customers increased only 1% sequentially. After rising sharply in the first part of the year, U.S. rig count now found a near term ceiling, a touch below 800 rigs constrained by among other things the availability of labor. North American E&Ps are citing service availability as the biggest risk to achievement of their production targets. But our oilfield service customers tell us that crew availability is the real root cause. U.S. oilfield wages in West Texas and North Dakota are up 20% to 50%, along with higher per diems, higher oil based mud bonuses, higher overtime as crews that are chronically shorthanded and they work extra hours to cover the unfilled positions.

But new hires are hard to find, and the crews that are successful in hiring new green hands are less safe and demonstrably less efficient. $4,000 per ton casing is another constraint, and it’s contributing to 40% higher cost per foot for E&Ps. Dwindling Tier 1 drilling location inventory in the reversal of double digit well productivity gains in terms of barrels per foot of lateral that fueled the rapid run-up in U.S. shale production several years ago are also emerging as constraints to production growth. And like the international markets, capital is scarce and expensive. Even the rising equipment utilization across North America in 2022 brought mercifully higher pricing, enabling land drilling contractors and pressure pumpers to begin earning much improved returns on capital, the industry is hesitant to invest.

For instance, U.S. high-spec land rig day rates around $40,000 a day can generate 20% capital returns on new build rigs for efficient contractors. However, new capacity editions so far have been scarce owing to capital, labor and supply chain constraints. On the other hand, pressure pumpers are cautiously investing in frac fleets given the higher wear and tear that simul fracs and 24/7 operations are placing on their spreads. They see the need to replace equipment they’re consuming every day at accelerating rates. It doesn’t hurt either that the returns on new frac fleets are approaching 40%. Importantly, though, they are self-funding these investments. This is external capital is still very difficult to access. Given the myriad of constraints 2022 has exposed, it’s no surprise that year over year U.S. production growth fell well short of the 2016 to 2019 era, and even fell short of greatly reduced expectations despite a massive drawdown in DUC inventory.

Now, add to the constraints I mentioned, the emerging North American gas oversupply caused by constrained LNG export capacity out of the U.S. and rising gas oil ratios in shale basins as they mature, and we foresee additional pressure on E&P economics and diminishing urgency to drill in North America. Higher pricing across the board will likely still lead to an overall increase in year-over-year E&P spending, but our outlook for 2023 North American land remains a little cautious in contrast to offshore and international land markets where investment urgency, utilization and pricing are rising. Longer term, we’re bullish on all basins in all areas, including North America, as a serious global structural shortfall in production becomes more evident.

This returns me to where I started. Constraints are everywhere in this industry. Years of limited exploration and reserve replacement now restrain the industry’s ability to ramp production quickly as the pipeline of developments has dwindled. FIDs in 2020 and 2021 are down 80% from 2009 peaks. Nevertheless, this is beginning to change. The events of 2022 taught us just how crucial the capital-intensive industry we serve is. Oil and gas is the industry that powers all other industries. Our way of life would not exist without it. Every upcycle shares some common trades. The cutting of maintenance expenditures and laying off of hard-working oilfield employees during down-cycles creates an urgent need to rebuild capabilities and teams and iron as we first enter an upcycle.

But never before has this industry faced the constraints we face today. From raw materials to finished components to workforce to freight to availability of capital to higher interest rates to hostile political pressure and tightening regulations, pivoting back to growth will be as daunting as it ever has been throughout the industry’s 164-year history. I’m convinced that these extraordinary constraints will elongate this upcycle. They will take many years to overcome. But we simply must overcome them to restore the critical energy security required for economic growth and improving standards of living, particularly for those living in energy poverty. That’s why I’m so very proud of the NOV team. Our employees are smart and hard working. They know the world is counting on them.

They innovate and create solutions. They hustle and work the problems. They get it done. And Jose, Blake and I are grateful to each and every one of them. Jose?

Jose Bayardo: Thank you, Clay. To quickly recap the quarter, NOV’s consolidated revenue grew 10% sequentially and 37% year- over-year with all three segments posting their highest revenue since the fourth quarter of 2019. While North America drove most of the growth during 2022, as Clay noted, momentum in international markets has been building throughout the year and outpaced North America in the fourth quarter, resulting in 14% sequential revenue growth in international markets and 4% in North America, which included strong growth in offshore Gulf of Mexico. Adjusted EBITDA for the fourth quarter totaled $231 million, or 11.1% of sales, representing an incremental flow-through of 20% sequentially and 29% compared to the fourth quarter of 2021.

We’ve recorded a credit of $8 million in other items during the fourth quarter, primarily related to positive margins realized on previously reserved inventory, which we deducted from Q4 EBITDA. With the improving market environment, we may continue to recognize such credits and EBITDA adjustments in 2023. Additionally, we expect to complete the termination of our U.S. defined benefit pension plans in the first quarter, for which we expect to recognize a pretax noncash charge for the recognition of all actuarial losses and accumulated other comprehensive loss which was $8 million as of December 31, 2022. During the fourth quarter, eliminations and corporate costs at the EBITDA level increased $11 million due to higher levels of intercompany transactions, expenses associated with the buyout of a JV partner and year-end true-ups to employee benefits and other accounts.

We expect eliminations and corporate cost to return to the $60 million range in the first quarter. Despite the increase in working capital arising from strong revenue growth, cash flow from operations was $154 million in the fourth quarter. Capital expenditures totaled $66 million, resulting in free cash flow of $88 million. As is often the case, we expect a meaningful seasonal use of cash from operations in the first quarter, but we expect to be free cash flow positive for 2023, the magnitude of which will be mostly determined by the rate of revenue growth during the year. We have a strong track record and remain committed to returning capital to our shareholders while maintaining a bulletproof capital structure. Since mid-2014, we have returned $4.7 billion of capital of our shareholders through share repurchases and dividends.

And since mid-2015, we have reduced our gross debt by $2.6 billion. As a reminder of our capital allocation hierarchy, we first and foremost seek compelling organic investment opportunities, which historically have provided us the greatest risk-weighted returns as we can appropriately leverage our installed base of equipment, existing manufacturing capacity, global distribution infrastructure, digital platforms and world-class R&D facilities. With the improving market environment and the progress we have made in new product development over the last several years, we see increasing numbers of attractive organic opportunities and are, therefore, increasing our capital expenditures to approximately $275 million in 2023. Next on the list of prioritizations is M&A, where we employ a disciplined returns-focused process.

We approach M&A as an opportunistic means to accelerate already defined organic growth initiatives. This means that we avoid being in a position where we are pressured to complete an acquisition, reducing the likelihood that we overpay. We prioritize high rate of return, sustainable long-term growth opportunities that leverage our core competencies. But as previously noted, we are committed to returning excess capital to our shareholders, whether it’s through increasing our dividend or a share repurchase program. While our balance sheet remains solid, the recent anticipated near-term uses of cash to fund meaningful growth in our businesses, along with an M&A environment that is looking a bit more constructive means that we are not ready to increase return of capital to our shareholders at this time.

We will continue to monitor sources and uses of cash as the year evolves and maintain a regular dialogue on this topic. Moving on to segment results. Our Wellbore Technologies segment generated $762 million in revenue during the fourth quarter, an increase of $21 million or 3% compared to the third quarter and 32% compared to the fourth quarter of 2021. Revenue growth was driven primarily by the second straight quarter of solid improvements in demand for our key drilling technologies in the Middle East, partially offset by a North American market that has plateaued and lingering supply chain challenges that delayed deliveries of drill pipe and motors. EBITDA grew to $146 million or 19.2% of revenue with soft flow-through due to a less favorable mix, lingering supply chain difficulties and associated costs required to expedite critical customer orders.

Our Grant Prideco drill pipe business realized modest top line growth that was limited by supply chain disruption, including delays in receiving steel and coating materials, which resulted in customer deliveries slipping from Q4 to Q1. Incremental flow-through was also limited due to a significantly less favorable product mix. Despite these challenges, Grant Prideco posted its highest revenue quarter in three years and received its greatest volume of orders for any year since 2014. Orders improved 25% sequentially with strong demand from the Middle East and a notable pickup from offshore markets. Our ReedHycalog drill bit business saw a meaningful decline in revenue during the quarter, driven primarily by a large Q3 shipment to Asia that did not repeat a drop-off in Canadian activity and weather-related delays in the U.S. Despite supply chain challenges that are restricting deliveries of roller-cone bits, the business continued to realize solid growth in the Middle East and in geothermal markets as is highlighted under the significant achievements in our earnings release.

Our downhole tools business reported revenue growth in the low-teens, led by a significant pickup of fishing tool sales into the Middle East and Asia Pacific. After realizing significant improvements during the third quarter, the operation had challenges procuring certain high-grade steel and elastomers needed for its high-spec stators, adversely affecting sales and rentals of the business units drilling motors. Despite the supply chain challenges and the resulting less favorable product mix, pricing increases instituted earlier in the year allowed the business to maintain respectable EBITDA flow-through. Our WellSite Services business posted a small sequential decrease in revenue primarily due to strong shipments of MPD equipment in Q3 that did not repeat.

The decline in MPD sales was mostly offset by solid results from the business unit’s legacy operations. And we’re seeing growing opportunities for both our solid control and MPD offerings in offshore markets, including Mexico, Brazil, West Africa and Guyana and growing momentum in key land markets in the Middle East. This improving outlook was reflected in strong bookings for MPD capital equipment orders, which should serve as a growth catalyst for this business during 2023. Our Tuboscope business delivered a solid increase in revenue driven by the operation’s fifth straight quarter of double-digit growth in its coating operations. The business realized strong demand for pipe coating services in the Middle East and Asia for its Thru-Kote pipe sleeves in the Middle East and for glass reinforced Epoxy TK liners in Latin America and Europe.

The business also continues to realize growing demand for its TK-Liner systems in geothermal applications and recently secured contracts for two new geothermal projects in Denmark, which will add to our total of more than 28 miles of large diameter TK lined pipe that we have delivered for geothermal applications since 2020. Our M/D Totco business posted another quarter of solid growth with outsized incrementals led by a strong improvement in the unit surface data acquisition operations in the Middle East, North America and Europe. This growth was partially offset by a small decrease in revenues from our eVolve wired drill pipe optimization services, resulting from capital sales in the third quarter that did not repeat. Outlook for our eVolve services remains bright with several customers signing new contracts and with demand for this service building in the Middle East.

The unit is also realizing greater adoption of its latest Max digital product offerings which are currently installed on over 150 rigs utilizing over 800 of our Max Edge devices to simultaneously provide real-time data analytics in the field and at the operator’s office. Additionally, we recently launched our Max Completions offering, which is remotely monitoring a frac job in the Williston Basin for a large independent operator. While we’re in the infancy of providing digital solutions, which drive higher levels of efficiencies for both drilling and now completion operations, M/D Totco’s success in developing industry-leading digital solutions beyond its legacy data acquisition systems has already allowed the business to achieve its highest revenues and EBITDA in eight years, and the outlook remains bright.

For our Wellbore Technologies segment, we expect demand for our key enabling drilling technologies to be supported by improving global oilfield activity, driving continued growth for the segment in 2023. However, we do expect seasonality to serve as headwinds to Q1 results, resulting in revenue and EBITDA for our Wellbore Technologies segment in the first quarter to be roughly in line with fourth quarter results. Our Completion & Production Solutions segment generated revenues of $738 million in the fourth quarter, an increase of 8% from the third quarter and an increase of 34% from the fourth quarter of 2021. Adjusted EBITDA increased $10 million sequentially and $64 million from the prior year to $66 million or 8.9% of sales. Sequential EBITDA flow-through of 18% was negatively impacted by a lower margin product mix.

Relative to the fourth quarter of 2021, flow-through was 34%, resulting from improved execution against supply chain-related challenges, better absorption in our manufacturing facilities and improved pricing. Orders increased 13% to $557 million, the highest quarterly bookings the segment has achieved since 2014. Also of note is that this was the segment’s eighth straight quarter with a book-to-bill over 100%. CAPS backlog at the end of the fourth quarter was $1.6 billion, up 8% sequentially and 24% year-over-year. Our Intervention & Stimulation Equipment business posted a strong increase in revenue, achieving its highest level since Q4 of 2019. The business is seeing a notable transition in demand from reactivations and refurbishment-related aftermarket work to new capital equipment sales resulting from our customers’ need to replace tired equipment with more efficient assets.

As Clay mentioned, access to capital remains difficult for the industry. But the good news is that many of our customers are now generating healthy cash flows, their confidence in a sustained recovery is increasing, and many are now looking to lock in limited delivery slots that require substantial lead times. These factors combined to drive another solid quarter of order intake and the fifth straight quarter in which the business grew its backlog. Asset replacements, new technology to improve efficiencies and economics, lower emissions and longer laterals drove our order book in the fourth quarter. After selling our first new coiled tubing unit into the U.S. in three years during the third quarter, we received orders for 6 new coiled tubing units, 3 of which are destined for service in North America.

We also saw a notable increase in demand for 30,000-foot large diameter pipe with 0.276-inch wall thickness to support completions of ultra-long lateral wells in West Texas. As noted in the press release, we booked 20,000 hydraulic horsepower of our eFrac pressure pumping equipment, and we also sold six hybrid electric IMAX wireline trucks as more customers see the opportunity to not only reduce emissions but to also lower their total cost of ownership by using our latest technologies. Also encouraging is that we are beginning to see higher demand from international markets, particularly from the Middle East. Our subsea flexible pipe business posted a mid-single-digit increase in sequential revenue. Margins compressed slightly as the effects of improving throughput were offset by a less favorable mix of projects.

Orders for the quarter remained strong and resulted in the unit’s sixth straight quarter with a book-to-bill greater than 1. Equally important, we are realizing increasing pricing power as much of the spare capacity in the market has been absorbed or committed and customer demand continues to rebound. Our XL conductor pipe connection business experienced a significant sequential increase in revenue driven by strong execution and product deliveries to support several large projects in Latin America and the Gulf of Mexico. While we expect the typical seasonal pullback in deliveries during Q1, strong orders and steadily improving offshore activity should support a solid year for this operation. Our Process and Flow Technologies business posted a slight sequential increase in revenue.

EBITDA was mostly flat after a strong rebound in the third quarter. While the effects of supply chain difficulties, shipyard constraints and inflation continue to pressure margins and push bookings to the right as operators recalibrate cost assumptions, recent customer conversations give us confidence in increasing FIDs which should result in a much stronger 2023 for this business. Our pump and mixture operations experienced a sequential decrease in revenue due to outsized shipments of pent-up orders from the lifting of COVID lockdowns in China during the third quarter that did not repeat. Bookings improved 55% sequentially and included a large equipment package for a pepper processing plant in New Mexico that will be able to process 30 million pounds of Cayenne Pepper Mash per year.

NOV will provide 120 fiberglass storage vessels, each equipped with Chemineer agitators to achieve optimal mixing, 13 Moyno progressive cavity pumps to handle transfer loading and unloading and our GoConnect digital monitoring and control system to provide the customer with real-time equipment and process data to fine-tune operations, maintain quality and ensure equipment reliability. The unit also won an award to provide 24 Moyno progressive cavity pumps for sludge transfer and polymer pumping applications at a wastewater facility that will treat over 450 million gallons of wastewater per day. Despite the strong industrial orders in Q4, we’re sensing that our non oil and gas customers are growing more cautious due to uncertainty in the macroeconomic environment.

Our fiberglass business posted flat revenue but delivered more than a 300 basis-point improvement in EBITDA margin due to a healthy increase in higher-margin offshore scrubber deliveries that more than offset the effect of the seasonal decline in fuel handling equipment sales. Orders remained strong and in addition to the previously mentioned tanks for the pepper processing plant the unit booked a large order for a semiconductor manufacturing facility in Texas. The strong order intake resulted in the business delivering its eighth straight quarter with a book-to-bill over 1 and an all-time high backlog going into 2023. For our Completion & Production Solutions segment, we expect seasonality and several large projects that are nearing completion to result in a mid-single-digit decrease in revenue with decremental margins in the 30% range.

Our Rig Technologies segment generated revenues of $620 million in the fourth quarter, an increase of $109 million or 21% compared to the third quarter and 44% compared to the fourth quarter of 2021. The strong sequential growth was led by our aftermarket operations. Four straight quarters of growing spare part bookings combined with improving global supply chains, led to a sizable increase in shipments. The segment also posted a solid increase in capital equipment sales, which benefited from the delivery of a new land rig to a private drilling contractor in the U.S. and from a higher rate of progress on rig projects in Saudi Arabia. Adjusted EBITDA improved $36 million sequentially to $88 million or 14.2% of sales. New capital equipment orders increased $135 million or 113% sequentially and totaled $254 million.

Book-to-bill was just below 1 times, a result of the 27% increase in revenue out of backlog during the fourth quarter. Total backlog for the segment at year-end was $2.79 billion, an increase of $26 million over the prior year. Fourth quarter orders were highlighted by bookings for the designs and jacking systems for two wind turbine installation vessels and a new BOP stack for a harsh environment semisubmersible rig. While demand for conventional rig equipment has improved three straight quarters, bookings remain subdued as contractors are still reticent to make large capital commitments. Encouragingly, both utilization and day rates for all major classes of rigs continue to improve. Land rig counts increased by 43 or 3% sequentially, almost all in international markets and average day rates continued to improve, up another 11% on average in the U.S. during Q4 as contracts roll off and rigs repriced to leading-edge rates.

Contracted offshore counts improved 4% sequentially with jackup rig utilization reaching 80% and drillships 78%, resulting in higher day rates and longer duration contracts. These improvements should translate into better cash flow and growing confidence and outlook for our customers over time. While equipment orders remain modest, demand for our products and services is heading in the right direction, and the industry cycle is going through its normal progression at a very measured pace. It starts with simple reactivations of highly capable warm stacked rigs that moves to less capable cold stacked rigs, which require more effort to reactivate and often need upgrades to compete for work. Then, once fleets reach sufficiently high levels of utilization and day rates and operators seek higher productivity through newer and more advanced technology, demand for newbuilds will eventually take hold.

We’re moving through this natural cycle in both the land and offshore markets, and that progression is reflected in our results. Revenue from land customers in our aftermarket operations bottomed in Q3 2021 and has increased 92% from the trough. With leading edge day rates for top-tier land rigs north of $40,000 in the North American land markets, returns are now at a level well above newbuild economics. While we delivered a new land rig to a private U.S. contractor in Q4, capital discipline remains strong, particularly among public drillers who still have stacked rigs to reactivate, and we’re not expecting many more orders for new builds in North America this year. Customers remain focused on being disciplined and on driving efficiencies in their operations.

However, we’re increasingly fielding calls inquiring about our new technologies that can potentially alleviate some of their pain points, including our ATOM RTX fully automated robotic system and our Maestro drilling power management system, which allows contractors to optimize power and fuel consumption during drilling operations and minimize emissions. In international land markets, the availability of modern rigs that can be cost effectively upgraded is significantly more limited. As a result, we have recently seen a meaningful improvement in the number of discussions we are having with customers regarding new rigs, particularly in the Middle East, Latin America and Asia. Aftermarket revenue from our offshore drilling contractor customers bottomed in the fourth quarter of 2021 and have increased 58% since that time.

While we are not yet having discussions related to new floaters reflecting the longer cycle nature of the deepwater market, we are having discussions related to orders for new jack-ups. Additionally, there are meaningful opportunities for customers to continue reactivating and upgrading stacked rigs and to complete the 14 drillships that have been stranded at shipyards in Asia since 2015. We believe these rigs can be acquired and fully kitted out between $300 million to $350 million, a price which should produce a strong return for contractors in a $400,000-plus day rate environment. We estimate NOV’s addressable opportunity to properly equip and finish these rigs ranges anywhere from $20 million to $125 million per rig, while access to and cost of capital for rig contractors remains challenged, it is improving and a customer recently acquired one of these stacked rigs.

All of these opportunities may take some time to materialize, but will eventually come. In the meantime, our volume of work from reactivations, recertifications and upgrades of the existing fleet continues to grow. As Clay touched on, we completed 15 such projects in the fourth quarter, including the reactivation of 9 previously stacked jack-ups. Additionally, we received awards for another 23, leaving us with a current backlog of 83 projects. In our wind business, the market for installation vessels remains strong as evidenced by the two orders for NOV’s proprietary NG-20000X vessel designs and jacking systems we received during the fourth quarter. We expect to see a decrease in demand for new wind orders in 2023, but we still expect a few orders this year and see a significant shortfall in available vessels needed to meet the forecasted demand for turbine installations in the €˜26 to €˜27 time frame.

If this forecast holds, it should translate into nearly a dozen additional opportunities over the next several years for NOV. While 2023 is expected to be a year of growth and improved profitability for our Rig Technologies business, we expect seasonality and the timing of projects to result in first quarter revenues contracting 10% to 15% with decremental margins in the 30% range. With that, we’ll now open the call to questions.

Operator: Our first question comes from the line of Jim Rollyson of Raymond James.

Jim Rollyson: Hey. Clay, going back to your comments about the offshore side and kind of the need for incremental investments and obviously the lack of capital or willingness to spend capital by some of the current owners, how do you see that playing out in terms of you mentioned who the ultimate providers of capital may be. But when you think about that just playing out and time frame of this playing out, how do you unpack that?

Clay Williams: It’s a great question. In our view, it’s already starting to play out as the major integrated oil companies, as the big national oil companies who need the offshore rig industry to go back to work and perform drilling services are sitting down with those providers. I think they’re being told, hey, you’re going to have to pay much higher day rates, you’re going to have to be much higher mobilization fees. You’ve seen day rates for 7th gen drillships, for instance, double year-over-year and now starting with the 4 handles pretty common. And so, I think there’s just this recognition of reality here that this industry, offshore drillers have been beat up pretty bad through the downturn and have limited access to capital, and someone is going to have to pay for that.

So the oil companies, I think, are the first ask on this. There’s other participants here as well. I mentioned, I think, in my prepared remarks that some of the shipyards that are sitting on rig construction projects that were stranded through the downturn are offering bareboat charters on those to drilling contractors, such that the shipyard can go out and find the capital to complete those projects, get those things out of their yards, transfer — make those assets available to drilling contractors to operate them. And then, another potential source of capital that we think is going to play an increasingly bigger role, are these sovereign wealth funds, which have very deep pockets. And they’re in these countries that rely on the petroleum industry to fund public services to balance their government budgets and so forth.

And so, they don’t appear to have the sort of constraints on lending to the industry that other provider — more traditional providers of capital have.

Jim Rollyson: Great. That’s helpful. And then just as a follow-up, when we think about kind of how things have unfolded over the last two or three years, obviously, NOV has made a lot of overhauling of the cost structure through the downturn, which is, I’m sure, enhancing margins as revenues start coming back. And as we think about this going forward, you mentioned supply chain issues and constraints there and just cost inflation around at plus pricing, which you’ve been working on clawing back pricing from where we were before. But maybe just a little bit of color on kind of where pricing sits on average because I know it varies by product line. But kind of where we sit now versus kind of pre-COVID levels? And as I think about margins going forward, how much room do you have in pricing versus just your volume?

Clay Williams: Yes. First, I appreciate the question. We’re very focused on — the short answer to your question is, prices aren’t high enough. We — in 2019, we started taking a lot of costs out of our organization north of $900 million a year. Then, we hit the pandemic shutdown with demand really falling away to almost nothing and discounting happened, right? So, we track pricing, among other ways through like looking at baskets of products that we sell on an apples-and-apples basis. And — so for many of those, we found that they felt kind of mid-teens by late 2020 or early 2021. Since that bottom, we’ve been pushing on pricing very intentionally. We’ve talked on prior calls about that and have successfully clawed back most of those discounts.

There’s lots of products that are priced now higher than they were in 2019. But the problem is that inflation has eroded a lot of that potential margin increase. And so, when we kind of step back and reflect on our financial results, given the heavy, heavy lift that’s happened here on taking $900 million out of our cost structure, the erosion of that through inflation, the recovery of pricing, margins aren’t really where they need to be yet. And so, one of the big focuses we’re going to have in the coming years continue to push on pricing, to continue to work towards an acceptable level of margins. But, as you correctly point out, we’re not out of the woods yet on supply chain disruptions. We’re still seeing inflation in a lot of areas that we work, there’s a lot of pressure on costs.

And so, we’re going to have to really continue to maintain a very high level of focus on pricing and trying to get to an acceptable margin.

Operator: Our next question comes from the line of Chase Mulvehill of Bank of America.

Chase Mulvehill: Just I want to follow up on orders. You talked a lot about kind of growing momentum in subsegments and maybe some conservatives — outlook and some others. So I don’t know if you can maybe just kind of take a moment and walk through both kind of Rig Tech and CAPS, just real quickly, and maybe point to things that the investment community should be paying attention to and focus on when we think about potential for growth in those segments in €˜23. And I guess, I don’t know if you’d want to comment, if you think that orders could actually be up for both segments in €˜23 as well.

Clay Williams: Yes. I’ll ask Jose to chime in on that as well. But broadly speaking, we — as I said in my prepared remarks, we’re a little cautious on outlook for North America. Heretofore, through 2022, most of our intervention stimulation equipment order book has really been driven by North America. We kind of see that pivoting over in 2023 and more interest coming out of international markets, specifically the Middle East, which previously was more focused on used equipment and pricing there hasn’t been as good. We’re hearing opportunities to improve pricing and also a desire to put higher technology equipment into certain regions in the Middle East and elsewhere around the world. So, we’re pretty excited about that. The other side of the Completion & Production Solutions order book really are producers, mostly focused on offshore projects.

And last year, projects felt like they were moving to the right a lot because of the high levels of inflation. I mentioned 30% sort of overall headline project cost increases weren’t uncommon. It’s a big sticker shock to a group of engineers at an oil company who have been working on a project for several years. I think as we move into 2023, the sort of lesson we’ve learned about energy security, I think there’s growing confidence around the highly constructive supply-demand outlook. And so, our gut feel is that operators are getting more confident about doing FIDs. I think, you’re hearing that from others in our space, too, that their expectation around FIDs, particularly focused on international gas and are moving forward. And so, our expectation is that has a pretty bright outlook as well.

On the rig side, yes, I mean obviously, offshore is looking up, but still a lot of hesitancy here really of all drilling contractors about putting a lot more capital into their rig fleets. But if supply demand gets tighter and tighter and tighter, day rates tend to get pressured up. And so, our expectation is that the demand may grow. One real interesting area though is in the area of workover. We’ve had a surprising level of interest and demand for those, and that’s within Rig Technologies. I think we sold something like 7 or 8, much higher spec workover rigs focused on longer laterals and a few other areas. But — anyway, it’s across the board, both segments, given the challenges that the oil and gas industry face in the coming year to restore energy security, it’s a pretty good backdrop, I think, to start from.

Jose Bayardo: Clay covered it extremely well, maybe just one or two other things to sort of weave in. I mean, obviously, the market environment continues to improve. We’re looking forward to maintaining really good bookings in €˜23 to what extent it really depends. And I think some of the commentary that Clay provided gives you an indication that there will be a little bit of a change in mix, particularly related to some of the offshore projects within CAPS. We can see some of our business units where we have had some of those projects kind of pushed to the right, pick up a little bit in €˜23. So, we’re looking forward to that. And then lastly, related to rig, just to tack on to Clay’s commentary, you mentioned or requested insights in the things that people should be looking for.

And I think our commentary sort of gives you a flavor that we’re seeing very steady improvement in our rig business, obviously started with the aftermarket businesses. They’re both well off of their bottoms. But also from a capital equipment perspective, we’ll — we’ve been seeing a lot of volatility in our bookings quarter-to-quarter, primarily related to the very large chunky bookings that we’ve had in the offshore wind space. We’ve had three really nice quarters in a row of improved bookings at the conventional rig capital equipment business. And one of the things that kind of distorts the booking — how you look at book-to-bill there is this massive backlog that we have associated with our Saudi rig manufacturing contract, which was that $1.8 billion of backlog, if you sort of strip that out in terms of the revenue produced by it and just sort of look at the quarter, excluding contributions from that facility, book-to-bill was a little bit over 100% from a conventional rig capital equipment standpoint.

And so, we’re hopeful that continues to trend upward as we move through 2023.

Chase Mulvehill: Okay. I appreciate the color. Maybe one quick follow-up. Investors seem to also be focused on kind of the Rig Tech aftermarket opportunities as the offshore activity was picking up. So, maybe if you could just speak to — I guess, I’m assuming that they had some nice growth last year. And given what you talked about, I think it was 23 — you launched new — 23 new reactivations in the fourth quarter. When you look at the opportunities for €˜23, what’s out there? Do you think it’s going to be more heavy shallow water or deepwater reactivations and some new builds? And how should we think about the aftermarket business in €˜23 versus €˜22?

Clay Williams: Yes. I mean broadly, as the offshore drilling industry goes back to work, they’re going to need more aftermarket spares. There’s certainly kind of a flush level of demand going into reactivations a little bit. The industry got really good at cannibalizing spare parts off of idled rigs and we’re rebuilding that to some degree. But 37 jack-ups contracted by Aramco, for instance, for Saudi Arabia, going to work higher levels of activity in Brazil. That all takes a lot of aftermarket to support. One of the big headwinds we faced in 2022 throughout the year was supply chain disruption of our aftermarket business. And what you saw in Q4 was the dam broke a little bit, better availability of casting since our manufacturing group really got after a 26% increase in their shipments into our aftermarket organization helped sort of underpin a 20% — roughly 20% sort of spare parts sequential improvement in revenue there.

That won’t necessarily repeat in Q1, but we’re making good progress and feel pretty good about the balance of the year.

Operator: Our next question comes from the line of Luke Lemoine of Piper Stanley.

Luke Lemoine: You touched on some of the underpinnings of this offshore cycle within Rig Tech with some of the bigger ticket items like floater reactivations, the stranded drillships between guys like Samsung and Hyundai and NVO jack-ups. I guess with these type of individual orders and the incremental floater demand that could be over 30 rigs over the next few years, what do you think the annual order potential is for Rig Tech a couple of years out?

Clay Williams: That’s a really hard question to answer, Luke. As Jose just said, it tends to be really, really lumpy. I would tell you the upward trajectory is good. And our expectation is we should continue to build momentum, supporting global drilling operations of all pipe and in offshore. But there’s been so much downsizing that’s happened since 2015 here. Our expectation is that we can really step up and generate good financial returns by supporting the industry globally without the rig newbuilds that we saw in kind of the prior super cycle. They come terrific. We’re prepared to grow and provide whatever the industry requires and hopefully, that will come to pass. But the basic sort of blocking and tackling of drilling does work through a lot of spare parts.

It’s a high margin, high incremental business for us. As well, we continue to innovate around a lot of technologies and products for the oilfield. Jose mentioned our ATOM RTX robotics system that we’re introducing this year, super excited about that. We sold that into both land and offshore operations. We’ve got a couple of different emissions reduction technologies, our Eco Booster hydraulic system, our PowerBlade regenerative energy capture system, our Maestro system, all help both land and offshore drillers reduce their greenhouse gas emissions. And so, I think there’s great opportunities for that. And then lastly, we talked a bit about digital solutions that we have available that I think will help shape order. So, we’re — as opposed to just providing iron, which we did a lot of in this last super cycle, I think the next up-cycle, it’s going to be smarter iron and higher value-added iron, which I think will pave the way for higher margins and higher returns.

Luke Lemoine: Got it. And then maybe on the stranded drillships, you talked about what the content value could be to you kind of $20 million to $125 million a rig, on the — floater reactivations we’ve seen the offshore drillers quotes. But what could the content value be to you guys kind of per rig from what you see right now?

Clay Williams: Yes. Every rig is different. They’ve been sort of stacked in different ways. They’re at different levels of completion. So, this is sort of the notional revenue range that Jose provided for kind of the rig reactivations. But as I mentioned, one of the bigger ticket items in that is potentially a second subsea BOP stack, which is like a $50 million way to make the rig compliant with the latest BSEE regulations.

Operator: Our next question comes from the line of Neil Mehta of Goldman Sachs.

Neil Mehta: Good morning, team. And congrats on the good orders here. I had a couple of cash flow questions. And the first is, just as you think about 2023, can you walk us through some of the moving pieces? Recognizing free cash flow is super challenging to forecast in a growth environment like we’re in right now, but maybe you can walk through the different components ranging from working capital to other considerations that you want us to have dialed in for €˜23.

Jose Bayardo: Sure thing, Neil. It’s a good question because there certainly are a lot of moving parts and pieces as we sort of think about 2023. And first and foremost, related to the near term, as we talked about in our prepared remarks, Q1 typically is a good seasonal use of cash with a number of payments that need to get made within the quarter. And then, the free cash flow tends to pick up, particularly in the second half of the year. But as we think about 2023, particularly, one of the tailwinds to us is hopefully continuing improvement from a supply chain perspective. However, with where we’re sitting right now, we’re still making sure that we’re doing everything that we possibly can to live up to our commitments to our customers.

And at times, that means maintaining buffers within our inventory base, overstocking in certain key critical areas that obviously is a drag from a working capital perspective. Also, we’ve had really, really strong growth during — to this point in the recovery, and we expect to continue to have strong growth through €˜23 and hopefully well beyond. So to be determined precisely how much normal working capital that will consume, combined with the ongoing supply chain issues. And then probably lastly, as we sort of look at the transition from €˜22 to €˜23, our revenue mix is going to become much more internationally weighted. And so international operations tend to have longer cash conversion cycles, combination of larger projects, things take a little bit longer to work through the system, meaning slightly higher levels of inventory to meet those project orders as well as longer DSOs associated with the international client base.

So, that’s kind of the headwind. And then otherwise, as you know, a lot of the things that we do are very large-scale projects that have large progress payments along the way and/or completion payments. And those are sorts of things that can make material differences from one quarter to the next. And so, that’s why we generally try not to get too terribly excited about free cash flow from one quarter to the next, but are really confident that we’ll have a build in working capital during the course of the year to coincide with the growth in top line, but ultimately, all that working capital translates into free cash flow in the future.

Clay Williams: I would like to add, too, our historical working capital intensity at 25% this quarter in the high 20% range is much better than it was before the prior super cycle. So, I think the organization has made a lot of progress in becoming more efficient around our working capital requirements, required to support top line growth.

Neil Mehta: Yes. That’s very clear. I think Clay, that’s – a follow-up. You guys have a terrific balance sheet here, and you made some comments around M&A. So, I just want your perspective on whether you would leverage that balance sheet to opportunistically add to the portfolio? And to the extent that is something you’d consider, do you see any logical areas for addition?

Clay Williams: Well, we’ve been very clear, Neil, over the years about the need for a strong balance sheet. And I would say, again, we’re not forecasting new builds anytime soon, but you go back to the last super cycle from 2004 to 2014, our top line grew 6.5-fold pro forma for our DNOW spin. And so the sort of the top line growth potential here is very, very high and it does take working capital to support that. So we need to be very careful to make sure that coming off bottom that we don’t pile on leverage. We’ve done a great job delevering through this downturn. And while it’s — the M&A space is getting really interesting and there are a number of stranded assets out there the PEs and other sponsors have had for a long time and are kind of looking to exit creating opportunities, we’re going to be — we’re going to continue to be very cautious, very careful, very focused on risk management through this process and make transactions that we do will be smart.

Operator: Our next question comes from the line of Stephen Gengaro of Stifel.

Stephen Gengaro: Good morning, everybody. Two things for me. One is — I don’t know if you have comments around this or not, but we’ve heard of a couple of manufacturers, one manufacturer who’s effectively financing new builds on the frac fleet side, on the side. How does this — how do you think about that and how do you think about that sort of impacting your order flow, if at all?

Clay Williams: I think we’re really good at developing technologies. We’re really good at manufacturing. We do that efficiently. We manage costs. I don’t think we’re very good at banking and financing. And I really, really — given my balance sheet comments around Neil’s question, I think we — I think everyone should be very, very careful about financing in this space, deeply cyclical and potentially fraught with peril. So yes, we’re well aware of in a couple of product categories where we face competitors that, for whatever reason, have put deals on the table. And I think coming out of really low volumes during the pandemic, that sort of prompted a lot of desperation. And so, we’ll see how that turns out for them. But we don’t need to practice. And we actually do this for financial returns, and we think the highest and best use of our capital is not investing in our customers’ fleets.

Stephen Gengaro: That makes sense. I just wanted to get your views. And the second, just on the wellbore side, can you just remind us when we think about the international versus North American mix? Just sort of how we should be thinking about growth in light of your comments on both the international and the domestic side as we think about €˜23?

Clay Williams: That’s about 50-50, Stephen. And you heard my comments around sort of our outlook for both areas. I did — I want to be clear, although we’re not necessarily expecting an activity increase in North America and I think the pressure on gas, you could even as modest decrease, we do expect that overall North American investment by E&Ps and overall revenue for NOV probably should be up in 2023, and that’s because pricing marched upwards across North America for most all participants in oilfield services throughout 2022. So, that kind of year-on-year comparison, that all kind of hangs together. I think the most — some of the most recent surveys point to kind of mid-teens year-on-year E&P, CapEx on drilling and completion work in North America. But I think it’s going to take that level of spending increase just to keep activity flat, if that makes sense.

Stephen Gengaro: That’s great. Thanks for the color.

Clay Williams: You bet. Thank you, Stephen.

Operator: Thank you. That does conclude the Q&A. I’d like to turn the call back over to Clay Williams for any closing remarks.

Clay Williams: Thank you, Valerie. I appreciate everyone joining us this morning and look forward to speaking with you again on our next earnings call in April. Have a great day.

Operator: Thank you. Ladies and gentlemen, this does conclude today’s conference. Thank you all for participating. You may now disconnect. Have a great day.