Nabors Industries Ltd. (NBR) Q3 2019 Earnings Report, Transcript and Summary

Good morning, and welcome to the Nabors Third Quarter Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After toward presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I would like to now turn the conference over to Denny Smith, Senior VP Corporate Development and Investor Relations. Please go ahead.

Good morning, everyone. Thank you for joining Nabors' third quarter 2019 earnings conference call. Today, we will follow our customary format with Tony Petrello, our Chairman President and Chief Executive Officer; and William Restrepo, our Chief Financial Officer providing their perspectives on the quarter's results along with insights into our markets and how we expect Nabors to perform in these markets. In support of these remarks, a slide deck is available both as a download within the webcast and in the Investor Relations section of nabors.com. Instructions for the replay of this call are posted on the website as well. Since much of our commentary today will include our forward expectations they may constitute forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. Such forward-looking statements are subject to certain risks and uncertainties as disclosed by Nabors from time-to-time in our filings with the Securities and Exchange Commission. As a result of these factors our actual results may differ materially from those indicated or implied by such forward-looking statements. Also during the call, we may discuss certain non-GAAP financial measures, such as net debt, adjusted operating income, adjusted EBITDA and free cash flow after dividends. All references to EBITDA made by either Tony or William during their presentations whether qualified by the word adjusted or otherwise meaning adjusted EBITDA as that term is defined on our website and in our earnings release. Likewise, unless the context clearly indicates otherwise references to cash flow or free cash flow mean free cash flow after dividends as that term is defined on our website and in our earnings release. We have posted to the Investor Relations section of our website a reconciliation of these non-GAAP financial measures to the most recently comparable GAAP measures. Now, I will turn the call over to Tony to begin .

Good morning. Thank you for joining us as we review our results for the third quarter of 2019. Before discussing Nabors' performance, I will offer some comments on the macro factors affecting our markets. These factors had a material impact on our North American customers' activities during the quarter. They also appear to be influencing their forward planning. During the third quarter, the average price of near-month WTI was $56 having traded as low as $51 in mid-August. This represents a nearly 6% decline versus the second quarter average. Natural gas prices also declined averaging just over $2.30 during the second quarter. In the most recent quarterly Dallas Fed Energy Survey E&P respondents cited low commodity prices as the main constraint limiting their growth. The lower customer activity in North America has also resulted from the combination of limited access to capital as well as investor pressure to generate free cash flow. Finally, macroeconomic fears related to trade wars and sluggish growth have increased customer concerns about future demand for oil and gas. These factors clearly accentuated the expected decrease in activity for the third quarter as our customers compensated the cash flow shortfalls with lower drilling and completion expenditures. Consequently, the third quarter average and exit rig counts for the industry fell well below prior expectations. We expect all of these macro elements to result in some additional reductions in Lower 48, drilling activity through the end of the year. During the third quarter in particular the U.S. Lower 48 land industry average rig count declined by 102 rigs an 11% reduction. I will have additional thoughts on this topic, when I discuss the results of our quarterly customer survey in a few minutes. For our international markets, the macro picture is one of improving pricing and gradual growth in activity. In those markets oil prices have still been supportive of incremental activity. Moreover our typical customer is longer-term focused in either a state-owned oil company or a large global operator. This provides a layer of insulation from the market pressures that exist in Lower 48. Consequently, we anticipate ongoing incremental demand for rigs across most of our international markets. Our U.S. Drilling results reflect the change in the market that occurred during the latter part of the quarter. At the same time our international business drove a significant increase in our consolidated results. Adjusted EBITDA totaled $207 million, up 4% from the second quarter. Our Lower 48 average rig count declined by less than seven rigs. At the same time, daily gross margin improved slightly due to stable pricing, excellent operating performance and a favorable rig mix. In our International segment, adjusted EBITDA increased by nearly 10%. This growth reflected significantly better operating performance across several markets. The balance of our segments were about on par with the second quarter. Notably, our Nabors Drilling Solutions segment improved despite the loss of content from idled third party rigs in the Lower 48. Although, short of expectations, this increase occurred as the content penetration per rig expanded, also the segment's results reflect increasing adoption of higher margin automated directional drilling and tubular running technologies Now let me discuss our view of the market in more detail. During the third quarter, the industry rig count in the Lower 48 averaged 886 rigs. Last week, the rig count stood at 800. That is down by 29 rigs from the end of the third quarter which stood at 829. Since the beginning of the year, the rig count has declined by 249 rigs or about 24%. As of last week, Nabors' rig count was down by only 13 rigs or 11% for the year in the U.S. Lower 48. Our relative outperformance, both operationally and financially, is the best testimony to the value-added by the quality of our rigs, operations and technology. At the foundation of this performance is our best-in-class safety record, which has steadily improved for the past eight years. 2019 is shaping up to continue that trend. As I have stated many times, we believe that the quality of our U.S. rig fleet is second to none. These third quarter results demonstrate that. Midway through the third quarter, we saw sharper activity reductions than we’re indicated in our previous Lower 48 customer survey. This decline occurred with the mid-August contraction in oil prices and with the emergence of recessionary concerns. Customers continued to adjust their operations' tempo to lower cash flows, capital constraints and oil price worries. Once again, in September, we surveyed our top 20 Lower 48 customers. The survey reflects some specific consolidation plans from recent mergers and minor budgetary constraints. The surveyed clients account for approximately 39% of the total Lower 48 industry rig count. The participants indicated that a further decline of about 20 rigs or 6% is planned through the remainder of 2019. Most of this net decline is concentrated in just two operators. Notably, nearly 60% of the respondents indicated no change. The June version of our survey, which was taken before the emergence of third quarter macro sentiment changes indicated a similar magnitude decline among a larger number of operators. However, that change resulted in an actual decline that was more than double the indicated level. The latest version of the survey indicates those customers largely completed their planned changes in activity during the third quarter. As a reminder, my comments on the survey reflect the responses of our customers. Their plans and activity levels can and do change over time. As I highlighted earlier, our U.S. Lower 48 rig count has held up quite well, particularly in the face of the current industry conditions. We credit the quality of our customer base and their strong appetite for our high specification rigs. These rigs comprise 95% of our working rig count. In West Texas, for example, the most active rig market in the Lower 48, our rigs are among the most competitive and highly sought after. We currently have 41 high-spec rigs including 16 of our PACE-X rigs in that market. The utilization of our X rigs is currently 93% in West Texas. We only have one idle X rig out there. Although, our high-spec utilization is also extremely high in the North Dakota and Marcellus markets, some gas markets have underperformed. These include the Rockies, East Texas and the Midcon where we have seen drops in activity and some pricing pressure. Within the industry, leading edge pricing for high-spec rigs has softened somewhat in recent weeks, although as mentioned, pricing trends vary by geography and type of plays. For the vast majority of our fleet, we have held the line on pricing, particularly in the most active basins in West Texas and South Texas as well as the Bakken. Our financial results reflect our pricing discipline. At the same time, utilization for our highest-spec most capable rigs in the Lower 48 remains approximately 90%. Market pricing for our rigs has come under some pressure as certain competitors have selectively discounted rig rates. Our focus remains the delivery of value and performance to our customers. Our results indicate we are succeeding. In our international markets, industry rig activity has been stable in 2019. Pricing in these markets appears to be strengthening. We have already deployed several rigs, not present in our third quarter rig count, and we'll deploy at least two more by the end of the year. Multiple opportunities remain for additional high-spec rigs in several markets. In our other segments, interest and performance in automation solutions is growing. Customer adoption of our innovations continues to increase. Operators realize tangible benefits from these products and it shows in our results. Now let me comment on our various segment results and highlights. For the third quarter, consolidated adjusted EBITDA totaled $207 million. This performance was up 4% compared to $198 million in the second quarter. Revenue declined sequentially by approximately 2% to $758 million. Several factors drove our results for the third quarter. Adjusted EBITDA in the international segment increased sequentially by more than $8 million or 10%. This improvement primarily reflects better performance in several key operating locations. U.S. Drilling adjusted EBITDA declined slightly in the third quarter by 3% despite a 6% decline in our Lower 48 rig count. Our Lower 48 average daily margin improved during this quarter as did U.S. Offshore. In Canada, although EBITDA increased somewhat, the market remained weaker than we expected. This affected both our rig count and average daily margin. In Rig Technologies, segment results declined modestly following higher revenue for the robotic systems in the second quarter. We are encouraged that the performance in Canrig improved sequentially. We achieved some notable highlights during the quarter. First, we deployed two high-spec [ph] rigs in international markets during the quarter. The first is a very large unit in Kazakhstan. The second is a highly capable new build M1000 unit in Argentina. All of these rigs are working for U.S. based majors or NOCs and should be accretive to this segment's margins beginning in the fourth quarter. During the third quarter, we again increased the penetration of ROCKit Pilot and Navigator. We increased the total job count by 20% in the third quarter. The number of jobs running for third-party directional drillers increased by a-third. We expanded our customer reach and are running automated directional drilling jobs with our Pilot system for 10 customers spread over six basins. Nearly 60% of our current Pilot system jobs are remotely operated. We are seeing a consistent uptake for Pilot. The initial rollout has been successful and we are now scaling. Canrig deployed the first unit of its next-generation Canrig Sigma top drive on the next rig in South Texas. This unit achieves industry-leading horsepower output in its class. It features a direct drive mechanism which reduces the number of moving parts, improves reliability and reduces maintenance. Sigma's performance advantages will be even more attractive for our clients drilling hard formations with high vibration in the Middle East and other markets. Now let me discuss our segments in more detail. First, U.S. Drilling. We currently have 99 rigs working in the Lower 48. This compares to an average of 107.8 for the third quarter and 101 at the end of the third quarter. During the third quarter, our average rig count decreased by seven rigs versus the second quarter. Even in light of this rig count, we managed to maintain our Lower 48 daily rig margins to 10,231 per day. International drilling. Our international rig count for the third quarter averaged 88 rigs, down one versus the second quarter. Despite this lower rig count adjusted EBITDA for the quarter increased by 10%. We realized the benefits of the performance improvement plans, which we previously implemented in Latin America and the Middle East. These resulted in improved uptime and better move performance. The rest of our international operating geographies were mixed and on balance stable. In Canada, our results increased modestly, as the market environment remained weaker than we expected. This market experienced only a very muted seasonal upswing. Our results were not immune to that. Drilling Solutions. Drilling Solutions' financial performance improved slightly versus the previous quarter. Encouragingly, this increase occurred in the face of lower Nabors' and third-party rig counts in the U.S. Our International results and tubular running services line were bright spots. Next Rig Technologies. Results in our Rig Technologies segment were essentially flat. This segment includes Canrig, 2TD and Robotic Technologies. Second quarter results benefited from significant milestone payments for our initial robotic drill forward projects. Now let me discuss our outlook by segment. In U.S. Drilling, for the fourth quarter, we believe our Lower 48 rig count should approximate the current level of activity. We expect our Lower 48 daily margins to decline by a couple of hundred dollars per day. Our U.S. Offshore and Alaska business should be essentially flat with the third quarter. In the International segment, we expect steady improvement, largely driven by increased rig activity. In addition to the two high-spec rigs which deployed in late Q3, we have additional units scheduled to commence during the fourth quarter. These include two platform rigs in Mexico late in the quarter. Our average rig count for the fourth quarter should increase by approximately two rigs. Our customer in Venezuela received an extension of its sanctions waiver. We expect to maintain our operations there, at third quarter level. All in, we expect fourth quarter International adjusted EBITDA, essentially in line with the third quarter. This sequential performance, from the increase in rig count, will largely be offset by the expiration of amortization of upfront payments. Drilling Solutions, in Drilling Solutions, we expect fourth quarter results approximately in line with the third quarter. Rig Technologies. Looking forward, we expect fourth quarter adjusted EBITDA for Rig Technologies in line with this past quarter's results. That concludes my remarks on the third quarter results and our outlook. Now I will turn the call over to William, for a discussion of financial results. After his comments I will follow-up with some closing remarks.

Good morning. The net loss from continuing operations attributable to Nabors of $123 million represents a loss of $0.37 per share. The quarter included $14.7 million or $0.04 per share in exceptional charges related to an income tax settlement, in a foreign jurisdiction and $8.5 million or $0.02 per share in after-tax currency losses from the Argentina devaluation. The third quarter results, compared to a loss of $208 million or $0.61 per share, in the prior quarter. Results in the second quarter included $99 million or $0.29 per share, in net impairments to intangible assets. These were partially offset by a non-recurring tax gain of $31 million or $0.09 per share. Revenue from operations for the third quarter was $758 million a sequential reduction of $13 million or 1.7%. U.S. Drilling fell by $15.6 million, or 4.8% driven primarily by reduced rig count in the Lower 48. Seasonal declines in the Gulf of Mexico and Alaska, also contributed to the drop. Rig Technologies revenue, decreased by, $9.6 million, reflecting a reduction in equipment sales and the prior quarter's milestone revenue, for robotic systems. On balance, revenue from our remaining segments increased moderately. Our average rig count in the Lower 48 of 107.8 declined by just under seven rigs some 2.5 rigs more than we had anticipated. Daily rig revenue, in the Lower 48 increased by slightly more than, $100 reflecting relatively stable pricing for our rigs and an improving mix. International drilling revenue at $328 million increased by $1 million, primarily reflecting improved downtime performance, in several of our larger operating locations. This improvement offset a slight reduction in segment rig count. Canada Drilling revenue at $12.2 million, increased by $800,000, Rig count increased fractionally as the expected seasonal improvement was muted and occurred later than anticipated. Drilling Solutions revenue of $62.3 million declined by $2.3 million, from the previous quarter. Our international activity increases were more than offset by lower activity in U.S. land. However, the incremental activity overseas provided us with significantly higher profitability, than the loss activity in the Lower 48. Revenue in our Rig Technologies segment was $10 million lower, at $63.1 million. The decreased revenue came primarily from lower sales of capital equipment, spare parts and repairs. Most of the reductions came from lower margin internal sales. In addition, in the prior quarter, we had higher milestone revenue, for a robotics, system project in the North Sea. EBITDA, improved to $207 million compared to $198 million in the second quarter, a 4% increase. This improvement was led by International Drilling, which increased by $8.4 million, while U.S. Drilling fell by $4 million, on the onshore rig count decline. Drilling Solutions, Canada Drilling, and corporate overhead reductions all contributed to our improved results. U.S. Drilling EBITDA of $120.9 million was down by 3% sequentially. In the Lower 48, daily rig revenue and margin held steady, with rig margins closing at 10,231. Our rig crew wage increase of $290 was offset by higher revenue per day, and by reductions in other operating costs. We expect daily rig margin to fall off somewhat to around the $10,000 mark in the fourth quarter, driven by market price erosion in a couple of regions. Our current rig count is 99 in the Lower 48. Rig count should average approximately a 100 rigs in the fourth quarter. International EBITDA, increased by $8.4 million to $95.2 million in the third quarter, despite a 0.8 rig reduction to 88 average rigs in the quarter. Daily gross margin increased from approximately $12,600 to $13,700. This improvement primarily reflects substantially better operating performance in multiple locations and further benefits from cost improvement initiatives in Latin America. Operational and cost performance in almost all of our international locations were somewhat better than the prior quarters. In the fourth quarter, rig count should increase somewhat due to the recent deployments of two rigs in Argentina, two in Russia, and another one in Kazakhstan. Two more platform rigs are scheduled for deployment in Mexico in early December. We currently expect international Q4 EBITDA essentially in line with the third quarter. Our fourth quarter forecast assumes stable rig count in Venezuela based on a recent extension of U.S. waivers until late January. Although fourth quarter average rig cash should increase by a couple of rigs, this incremental activity will be offset by an $8 million reduction in amortization of advanced payments in Saudi Arabia and Kazakhstan following the recent contract renewals. Canada EBITDA increased by $400,000 to $1.5 million. Rig count at 7.7 was marginally higher and daily margin increased slightly to $3,800. The market in Canada has fallen more than expected and although recovering from the seasonal second quarter decline, the rebound has been less robust than usual. We now expect a modest seasonal increase in activity for the fourth quarter with a three-rig improvement in rig count and margins around the $5,000 mark. Drilling Solutions posted EBITDA of $23.5 million, up from $22.5 million in the second quarter. Among product lines, the largest improvement was in tubular running services as our activity continued to shift towards higher margin integrated services. The balance of our NDS product lines declined modestly in the third quarter, driven by the lower U.S. rig count. For the fourth quarter, we are targeting EBITDA in NDS similar to the third quarter. Rig Technologies delivered EBITDA of $2.2 million in the third quarter as compared to $3.2 million in the second quarter. EBITDA improved in the core Canrig equipment business due to a better mix. The fourth quarter EBITDA should essentially mirror the third. For Nabors as a whole, we would expect EBITDA to be in the range of $200 million to $205 million in the fourth quarter. Now, let me review our liquidity and cash generation. In the third quarter, free cash flow after dividends defined as net cash from operations, less cash used for investing activities, minus dividend payments was $74 million. This compares to approximately $82 million in the prior quarter. The third quarter included semiannual interest payments of approximately $70 million as compared to minimal interest payments in the second quarter. We also continue to implement initiatives to reduce our working capital. These are required to offset recent trends in our accounts receivable. Through the third quarter many customers have delayed their payments. The impact of these delays has been approximately $85 million versus our year-to-date target. Capital expenditures of $87 million in the third quarter fell by $43 million below the level of the preceding quarter. We are now targeting $400 million to $410 million in CapEx for the full year. With the absence of semiannual interest payments and additional CapEx reductions, our free cash flow should increase significantly in the fourth quarter. We also expect reductions in our working capital as we continue our push on receivables and other cash generation initiatives. We remain focused on improving our cash flow while decreasing our leverage. We maintain our commitment to reduce net debt in excess of $200 million this year. We're currently working on our budgets for 2020 and on updating our cash flow forecast for next year. Our 2020 plan will be prepared with an objective of generating minimum free cash flow of $300 million. Our plan will include a reduction in CapEx to a level well below $400 million and continued focus on cost optimization including overhead, field support costs, and operating expenses. With that, I will turn the call back to Tony for his concluding remarks.

Thank you, William. I will now conclude my remarks this morning with the following. During the third quarter, the slowdown in the Lower 48 rig count accelerated as we moved through the quarter. This reduction in activity caused a knock-on effect on our Drilling Solutions segment. Over the same time period there is little evidence of any similar trends in our international markets. In contrast, the demand outlook in those markets remains favorable. We just completed a couple of impactful rig deployments and we have additional deployments scheduled this quarter and next. In fact I am pleased with the activity in international markets across all of its relevant segments. This performance has been a real bright spot for the company. Against the market backdrop in the U.S., our Drilling business is performing well. The utilization of our high-specification rigs is still approaching 90%. We have shown the ability to put rigs back to work relatively quickly. Nearly three quarters of our Lower 48 fleet currently works for super majors and large independents. That penetration demonstrates the value that we deliver to this demanding group of customers. In Drilling Solutions, our technology suite is expanding. The growing penetration of our leading-edge Navigator and Pilot directional drilling automation systems is encouraging. Despite the current market headwinds, we continue to validate the value we offer to customers. We remain committed to realizing the significant profitability potential of the NDS portfolio. Our portfolio of businesses is unique in our sector. We have asset class diversification across several categories, domestic land drilling, international land drilling, offshore, well site services and technology. We also have geographic diversification with presences in both international and North American markets, which together account for 70% of the world's oil and gas production. This diverse portfolio is a source of strength. Growth in our International, NDS and U.S. Offshore operations, led to a sequential increase in total EBITDA. Approximately two-thirds of the company's EBITDA is sourced outside the Lower 48 land rig market. In other words, the majority of our business was stable if not improving throughout the quarter. I firmly believe the company's performance in a relatively soft U.S. environment confirms that we have the right assets, people and technologies in the right places. Our goal is to capitalize on this situation. We remain focused on restoring our businesses to solid profitability and returns on capital. That concludes my remarks this morning. Thank you for your time and attention. With that, we will take your questions.

We will now begin question-and-answer session. [Operator Instructions] The first question comes from Connor Lynagh with Morgan Stanley. Please go ahead.

Thanks, good morning guys.

Good morning.

So pretty impressive free cash flow target you've laid out for next year. I'm wondering obviously we're early in the budgeting phase. But if you could just walk through at a high level the big factors bridging you from $200 million this year to $300 million next year. What are the big moving pieces there?

William will do that for you.

Hey Connor. So we're expecting to see about $200 million this year like you just said. Obviously, we're just starting our budgeting process, but we have plenty of preliminary indications first of all that we expect to see our EBITDA higher next year than this year. So that should be incremental and we're not ready yet to discuss by how much higher, but that's part of our plan. Secondly, I think we're going to cut our CapEx by another $45 million next year. Interest expenses should drop by about $20 million. And if you may recall in the first quarter of this year, we did pay an incremental $11 million or so of dividends. Then we cut the dividends after that. So those $10 million should be accretive to our cash flow for 2020. If you add that all those things up to the $200 million, you end up I would say comfortably above $300 million.

Got it. That's helpful. And just thinking about the fourth quarter cash flow, how contingent is that upon a working capital release? How do you think about what is going to be better to the downside there?

I mean the biggest pieces though are more like the interest expense which is going to be about $70 million lower. I think our CapEx is going to be another $45 million lower from what we saw in the third quarter. And of course, we -- part of my job is to make sure that we have the most efficient working capital for the size of our business and we have our team very focused on that. Some of that may come from the working capital. Obviously year-end is tough to gauge how well customers will pay, but we do expect to squeeze a bit a few tens of millions of dollars from working capital in the fourth quarter. In addition to that, we do have idle assets that are noncore and those are not big numbers, but maybe a couple to three tens of millions of dollars as well in the fourth quarter. Again, that's part of our ongoing process and I think in the fourth quarter, we'll see somewhere in the range of $20 million to $30 million in asset sales as well.

Okay. Thanks very much.

You’re welcome.

The next question comes from Scott Gruber with Citigroup. Please go ahead.

Yes, good morning.

Good morning.

In September, I think you entered a accounts receivable purchase facility. Did you sell any receivables during the quarter? Was there a benefit to cash from any sales there?

The way I view this Connor is that we signed an agreement to sell those receivables and we sold some. So why did we do this? I hate to say this, but our customers have been delaying payments more than usual this year basically not meeting their payment commitments and paying on time and that started pretty early this year. So I guess those delays have something to do with the push on cash flow that they're getting from their shareholders. But the fact is that year-to-date we've underperformed in collections and our DSO has suffered as a result and we deteriorated every quarter this year. So the impact is here and our working capital is about $85 million. So the way I view this agreement is defensive. So we use that to compensate some of the erosion or deterioration in our DSO and whenever we have needs. For instance, we bought about $50 million of bonds recently and we paid back some of our revolver but I guess, the receivable does allow us to offset this unfavorable impact by accelerating the delayed collections and bringing the DSO to the number it should be and it has been in the past. So obviously, we're not just using this accounts receivable sales to mitigate the impact. We're also countering these customer tactics by trying to improve our internal DSO. So we're trying to get our invoices out -- quicker out the door and get them approved by clients and we're also invoicing more frequently. We have our management team doing high-level client visits. We recently went to see PEMEX for instance. Our President of Operations went there -- of global drilling and we got a very nice collections. And making no mistakes and invoices rapid disputes, you name it, everything we can think of, because in the future, if we have any sales of receivables, we want this to result in incremental liquidity rather than to make up for those slower collections. So we did offset some of the -- I would say delays in payments with the collections in the third quarter. We sold somewhere in the $90 million range to offset that and some of that was collected before the quarter end by the way.

Got you.

Thanks.

No. It makes sense and we're certainly hearing about it from others. I mean, one kind of how widespread is the DSO disappointment by geography? We're hearing that domestic E&Ps are stretching. Are you guys seeing that as well? And is this just the new normal in terms of kind of the days that they're targeting?

I don't think it's a new normal. I don't think it's a new normal it's the usual normal clients. And -- but it's true that they're getting a little bit more cash flow pressure. So right now they've ratcheted their excuses up a little bit. But I mean that's the usual game. We have always the clients play that game and then we have -- I mean, we've been doing this for a long time. So we know how to counter that and what are the counter tactics that we use to make sure that they don't -- they do that to somebody else and not us. So that's part of the game that goes on all the time and I think we're very cautious that is going on and we're not giving -- we're trying to remove excuses from clients to take advantage of the situation and delay their invoices. But that's the usual game. It's not a new normal. It's a usual norm but it just -- this year, I think a lot of clients started using those tactics a bit more. And it's in the U.S. yes, but in places like Latin America, we saw a lot of that. I mean the valuation in Argentina, allowed some of our clients to claim some excuses to delay and renegotiate and things like that. So we see that all the time but I must say that this year we've seen it a little bit more than usual. And like I said, that's been, we've had a tough year this year in the first couple three quarters. The impact has been in the $80-plus million range.

Got you. If I can just ask one more quick little question we get on Nabors is just given the moving pieces, how do you guys think about maintenance CapEx for the organization as a whole? And I'll turn it back.

So for the organization as a whole is obviously maintenance CapEx depends on the rig count. But I think our bare bones maintenance CapEx, the lowest we can get it to is somewhere in the high 100s like 180, 190 but that's pushing it a little a more. A more normal number would be somewhere in the low 200s, and again, that's very much dependent on rig count, right?

At the current rig count you could do the low 200s?

At the current we can get under 200 at the current rig count, yes.

Okay. Got it. Thank you.

The next question comes from Kurt Hallead with RBC. Please go ahead.

Good morning.

Hi, Kurt.

Hi. So my -- I think one of my follow-up questions here just stick on the financials for a second would be, when you generate the net -- reduce net debt as you go into next year can you help us understand if there's going to be -- is there going to be an absolute debt reduction into next year William? Or is it just building cash on the balance sheet?

No. I mean, it's definitely going to be a reduction next year. I mean the minimum you're going to see is about $285 million, which is the 2020s that mature in September of next year. So that's going to be the minimum reduction but I would expect to see a much bigger reduction than that. As you can see, the initial outstanding on the 2020s was about $600 million and we're now at $285 million. So we've been picking at it and we've been picking at the 2021s and the 2023s. I think those three maturities will fall very significantly during, 2020 during the next -- this coming year 2020.

Okay. Got it, thanks for that additional color, and Tony on your end you do that survey of the customer base every quarter. As you kind of maybe step beyond that have any E&Ps really given you -- or do you have a high degree of conviction on what the E&Ps have given you in terms of indication on how they're going to start 2020?

Obviously, this is the topic du jour. I would say it's a little too early to talk about it. It's a little premature. I can't say there's been a great deal of dialogue. And interest from them, in contracting additional high-spec rigs. Obviously, the commodity price has to cooperate. And the overall macro moves that's a big issue. But I think the early indications are yes. And directionally, you can see from William's comment that we are always think we're going to be up. So -- and we're pretty clear about our average rig count for the fourth quarter. And we said directionally, next year it's going to go up.

Okay got it. And then in the context of dynamics that play through the fourth quarter where you indicate some competitive pressures and cash margin degradation. As you again think through that process? Or we try to think through the process into next year, do you get a sense that, pricing should stabilize? Or do you think that there's still going to be some fleet through on pricing as you get into the first part of next year?

Again, I think, the visibility is limited. And I think you have to be really careful when you talk about pricing. I mean, there's a lot of talk going around. Got to make sure you're talking about apples-to-apples here. I mean, you've heard, people talk about day rates in the low teens. I would be surprised if you found rigs of the same calibre, as our rigs with the same kit. And we're placing the mid-20s at those rates. When you break it down, you have to segment markets here in the U.S. In the oil markets, as we indicated, I think there, there's a little weakness maybe as much as $500 a day. The real weakness is in the weaker gas markets. That could be up to a couple of thousand dollars. We've been able to navigate this with our focus on the oil markets and the shift in mix towards high-spec rigs. We don't see a reason to re-price our fleet down, to just get utilization on a few rigs. That doesn't make any sense to us. And -- but having said that, we haven't lost a rig to a competitor undercutting us. So, and as you know, the top four drillers account for the lion's share of high-spec rigs. And they've been relatively disciplined. That all added to a pretty supportive environment. I don't think, that's changing, as I look going into next year, again that is some big event that we haven't seen occur yet.

No. That's great, that's great color. Thanks, Tony I appreciate it.

The next question comes from Chris Voie with Wells Fargo. Please go ahead.

Good morning, guys.

Good morning.

Good morning.

Just curious about the $8 million amortization benefit, compared to flattish EBITDA in 4Q, is that going to continue. And be persistent through 2020 and going forward?

So the amortization is actually not a benefit. It's the other way around. We had it through the third quarter. The contracts expired and were renewed. So those were -- those contracts had significant upgrades and -- those were paid at the beginning of the contract. And were amortized over the life of the contract, right? So those $8 million were in the third quarter, but it won't be in the fourth, right? So that's what's offsetting the incremental rig count and some cost -- continuing cost initiatives that we are implementing in South America and the Middle East. So those things, we have some positives. But those are being offset by -- in terms of accounting, revenue in the -- from the amortization of the deferred revenue. What you need to keep in mind though, is that, if we have the same EBITDA in the fourth quarter versus the third that means our cash flow should be some $8 million better because that's non-cash, right?

Right, yes. That's what I meant. I guess I didn't express it correctly. That will be persistent going forward.

Yes that should be persistent.

Yeah, okay. And then I am just curious on the technology front. I think, maybe one of the things to reduce costs going forward could be progress on de-manning rigs to some extent. Just curious, if that is a near-term potential. And to what extent, you think, you might be able to capture any benefits from doing so, versus passing through to EMVs specifically, in the Lower 48, I am just curious your thoughts on that.

Sure. Well a large portion of NDS service portfolio is in fact to provide a better -- so all-in solution. And by better, I mean automation. And automation looks at the workflows and tries to squeeze out not just bodies, but extra processes. So, that's the real value proposition. So as we said in our notes here, with respect to casing running for example, we've managed to come up with a solution now where you can add our new casing running tool to a top drive and effectively automate most of what a typical five-man casing crew does with less than half the people. And that's what's catching some traction now big time. And we think, similarly, on directional drilling, as we mentioned 60% of the jobs we're running, are now without direction drillers on site. We have a remote operation center that can supervise several wells at the same time. But I do think that's the future. And I think this concept is resonating with customers as they look for different ways to achieve their BOE lower cost objective. I think, unless operators really start thinking outside of the box -- excuse me to redo their workflows you can't get there. So there's some convincing that has to go on to make that happen.

Okay. That all makes sense. But should that ultimately drive a lower cost per day as well and essentially some margin-per-day tailwind from that?

Absolutely. Yes. Absolutely.

Or we're going to see incremental NDS revenues?

On the rig side?

Yes.

On the rig side, in terms of lower costs for bodies, I don't see saving rig crew people yet in terms of reducing the number of buys on rig crew. What I see is the rig crew being used more effectively maybe to absorb other valued added tasks around the rig. And therefore the revenue produced per body by them will go up. That's the way we're looking at it. The rig is -- the natural consolidated around the world and I see that all the time. In my thesis here if you actually look at our industry the only person at a well site from beginning to end is the drilling contractor. Everybody else comes and goes. There's about 300 guys. They go to the rig site, it's matter you throw in the course of the well. So the rig crew is actually the natural consolidator and we intend to make that the focus trying to get more out of that core group of people. So that's not necessarily reducing them, but figuring out how to use them more effectively with higher value-added tasks. If we're correct with the new stuff we have going on which is automating the whole drilling process we'll actually free up those five-man crew guys to do other things as well. So that's our objective to repurpose them.

I'll make a comment on that Chris. I mean the casing running has been one of the stars of NDS along with the performance software. And in fact in the first quarter, we had a vast a vast predominance of conventional jobs with a full complement of people and that has shifted dramatically by the third quarter. So in the first quarter we lost money in U.S. land in conventional or in casing running. In the third quarter, we made a nice amount of money with about half the jobs that we were doing before because we shifted -- we shut down some of our conventional jobs and replaced them with integrated jobs and it's in the process. We're now making significant amount of money in the U.S. Lower 48. So yes, I mean, some of these automation initiatives are certainly resulting in lower cost for Nabors at no sacrifice to revenue.

That's helpful. And on a related note one of your competitors mentioned the cushion between the reported revenue per day and just the base day rates is probably a few thousand dollars. Is it a bit higher for you guys given additional services? And is that pretty consistent over time?

No. I mean, I don't -- I mean a lot of people talk about the base rate, but that's a fiction. Every client -- clients are very different from clients negotiate an all-inclusive rate. Others negotiate little pieces. So we don't really have like a base, base rate. We are placing our rigs in the $26 or $25 to $26 range. And most of the clients take up the same thing the same services. So I mean a lot of people talk about base day rates, but in today's market the decline is just in terms of how much it's going to pay per day and then they're going to try to get as much as they can for that amount of money and most clients get most of the same things.

And the clients really have an AFE with a target number to make the economics. And so they're trying to solve for that number and figure out what the best combination of a solution is for that and that's what we're good at providing for them.

Some guy's base rate is $25. Others is $23 depends on what they call the base rate, but it's not a big -- fixed definition for that.

Okay. Thank you.

The next question comes from Praveen Narra with Raymond James. Please go ahead.

Hi. Good morning guys. I guess I just wanted to follow-up on one of Scott's questions on maintenance CapEx. If the environment stays kind of similar to where it is now and how we see 1Q 2020 shaping up, is it fair to presume that U.S. rig CapEx would kind of be at that maintenance mode in 2020? Or is that an unfair presumption?

The U.S. rig count is pretty -- the U.S. rigs are pretty well maintained. And therefore, on the lower side it could -- we could actually run it at that level on lower side. So, on the U.S. side, I think I'm pretty confident on the ability to sustain it for a while on the U.S. portion.

Okay. Perfect. And then just a quick one for me. There's a change of ownership in Alaska. I know it's still early days. But I guess, there is been some discussions on change in development plans for those assets. Just curious your guys' thoughts on how that could shape up and its impact on Nabors?

I think it's been good for the industry. And Jeff Hildebrand and his team is amongst the best operators in the country as you know. I think they are the best privately run company with E&P and most successful in the country. And I think it's good for the industry, because I think one of the three anomalies has been you have a major world resource up there with no geological risk and a pipeline that's half full and it's always made no sense to me why that's the case. And I think Jeff and his team will figure out a way to actually make a lot of money, and hopefully it's going to trickle down to everybody else.

Okay. Perfect. Thank you.

I think let's we’re running out of time. Let's just take one more question, please and close the call out.

The next question comes from Taylor Zurcher with Tudor, Pickering, Holt. Please go ahead.

Hey, thanks for squeezing me in. First question, as it relates to Latin America, it looks like a couple of rigs went down in Q3 in Colombia. So curious if you could share some perspective as to what you're seeing in Colombia. And then secondarily, in Argentina, you're obviously adding a few or a couple of high-spec rigs in Q3 and Q4. At the same time, there's a political regime change that'll soon to happen in Argentina. So maybe it's too early, but to the extent that might have any impact on your business moving forward just curious to hear your thoughts there.

Well, as you correctly summarised, yes, we have two rigs going in Argentina. That's three of the seven that we referred to. Our current rigs have only thinks that -- I think that the market is such that we don't see anything really troubling right at this point. The sanctions we have in Venezuela was extended, and the elections in Argentina we haven't seen any negative impact from that. In Colombia, I'll let Edgar say something about Colombia.

Yeah. So for Colombia, we have I would say two different classes of rigs. Of course, we have the high specs and the high specs have very high utilization. And then we have some legacy rigs with a lower aspect and those are the rigs that you see came out of the count during the quarter. We believe that there were some challenges both in terms of budget and in terms of the ability of the customer to have the program ready for execution. We believe that as time goes by, of course, we expect to have the same very high utilization on the high spec rigs. And as the next year comes in, I would say hopefully the programs for the legacy rigs will be in place and we'll see the activity and go up again.

Okay. Got it. That's helpful. And then, a follow-up on the JV with Aramco, I know we're still a ways out from those new builds really starting to flow through, but could you give us an update as to how the discussions around the construction of the new build program are progressing thus far? And then for 2020, should we expect a portion of CapEx to be budgeted for the down payments for the first five new builds? Or is that more of a 2021 event?

All right. Before I get that, let me just make an overall comment, which is that I think our position there is very sound. And I think as we've informed you previously, we basically renewed virtually all our rigs for 2020. So we have a stable rig fleet in 2020, and we have an additional rig. One of the seven rigs, we talked about is the additional rig coming up in the first quarter. So that sets the -- kind of the base environment here which is very sound. The joint venture, I think there's been a little bit of slowness on the manufacturing facility for the new manufactured rigs. The reps were having yet issues, the order for the new rigs, but we're looking towards the end of the year for that to happen. And in terms of CapEx, I'll let William talk about what we're thinking about how it's going to fit into the time scale for 2020.

So, in the CapEx that we're budgeting for next year, we have included a conservative expectation that we will have some expenses in 2020. I think it's somewhere in the range of $50 million for initial payments. Of course, the rigs will not be ready, but we have budgeted -- put in the budget about $50 million. That may turn to be a little bit conservative. Discussions with both Aramco and the manufacturer of the rigs in country indicate that the timing may slip a little bit.

Understood. Thank you.

Ladies and gentlemen, we'll wind the call up now. And as always, if we didn't get to your question or if you have any other questions or comments just feel free to call us or e-mails. Thank you very much. Jake, do you want to close this out?

Yes. This concludes our question-and-answer session, and I'm going to turn the conference back over to Denny Smith for any other closing remarks.

No. That winds it up. Thank you, ladies and gentlemen for participating.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.