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With those rigs, we added significant term backlog at attractive rates and margins, and our total number of super-spec FlexRigs increased to 230 at quarter end, representing more than 40% of the industry's U.S. super-spec capacity. Our current U.S. rig count is approximately 220 FlexRigs.

Considering the trends we are seeing in rig releases, the higher levels of churn across certain basins and the current demand, we believe the company's rig count will bottom out early during this third fiscal quarter, and FlexRig super-spec utilization will remain in the 90% plus range. Importantly, this level of utilization should be supportive of the current pricing environment.

Another factor that is supporting super-spec pricing is the top five U.S. land drillers own approximately 80% of the active super-spec fleet. With the industry super-spec fleet already over 90% utilized, this degree of supply concentration also promotes a sturdier pricing environment going forward.

The oil price for WTI is up over 40% since the beginning of the calendar year. In past cycles, this kind of price action would bring on higher activity. Yet today, we are seeing a more tempered response and even reductions in activity by some in the industry. Clearly, customer behavior is changing, and the movement is toward prioritization of cash flows and less focus on growth. This returns focused approach has put additional emphasis on disciplined spending and determining where value can be added to improve performance and long-term cash flow.

Principles that are focused on returns resonate with H&P and are aligned with our goal to deliver performance to both the customer and the shareholder. We believe we are exceptionally positioned in this kind of environment with the right hardware, a FlexRig fleet that is an industry leader in drilling unconventional wells and with the right software, a digital technology platform focused on wellbore quality and placement that when deployed on a rig are proven to improve well economics. Further, these principles align with our own capital allocation policy, part of which includes returning cash to shareholders through our dividend for the last 60 years and with an increasing dividend over the past 47 years.

On our January call, we said our customers had a mix of outlooks regarding CapEx. They were up, down, and flat. We also expected our customers would be setting their 2019 budgets with an expectation of $50 to $55 WTI. We compared the public company and majors announced CapEx budgets for 2019 compared to 2018 and found the total budgeted CapEx is only down approximately 5% year-over-year. This supports the view we expressed on our January call that the rig count reduction would likely be less than a 100 horizontal rigs. And thus far, the rig count is down approximately 70 rigs.

Further to that, H&P's top 25 customers, which represents about 80% of our working rigs, reduced their CapEx budget by an aggregate of approximately 4% for 2019. Even with the current price of approximately $65 a barrel, we are reticent to expect that the overall industry rig count will do more then remain flat through the rest of this quarter.

Of course, there is the caveat and I would like this to be true. Oil prices remained strong and we experienced less oil price volatility, and the rig count improves in the back half of 2019. We know of at least one public E&P who has index or capital allocation strategy including CapEx to align with the price of WTI. If that practice is more common than we know, and if the private E&Ps would take advantage of higher oil prices, perhaps, we'll have better rig activity than flat in the second half of 2019.

With the trend toward multi-well pads, the industry has ushered in the need for additional manufacturing type requirements. It isn't sufficient to only drill wells fast and efficiently anymore, but it's also important to have a higher quality, reliability and more accurately placed wellbore. Industry studies have documented that wellbores with less tortuosity produce more oil and more accurately placed wellbores produce fewer parent child well interference issues. Both of these factors are important to consider as customers want and need to do more with less.

I will touch on this more in a minute when discussing our new H&P Technologies segment. Let me begin with our first milestone achieved during the quarter. We have a commitment to send our first super-spec FlexRig overseas. We have long believed H&P's drilling leadership position in the U.S. unconventional basins would lead to further international opportunities to deploy our U.S. super-spec FlexRigs, our FlexApps and our H&P technology software solutions, including other slide and deploy those overseas. That has come to fruition as we signed a letter of intent to deploy our first super-spec FlexRig from the U.S. land fleet to Argentina later this quarter.

We are excited about this opportunity and not only what it portends for H&P's Latin American business, but other international locations as well.

Now, let's shift our focus to the H&P Technologies segment and the second significant milestone. During the second fiscal quarter, H&P commercialized its drilling automation technology AutoSlide. We believe AutoSlide is the next evolutionary step in drilling automation that is scalable on FlexRigs as a result of our uniform FlexRig operating system.

Our software-based offerings from our H&P Technologies segment with Motive and MagVar, along with our FlexApps which are designed for FlexRigs to enhance downhole tools life and drilling performance. As I mentioned earlier, as customers continue to push the envelope on manufacturing drilling, the benefits of H&P technologies have a meaningful impact on well economics by improving production dynamics and lowering the risk of wellbore interference, thereby bolstering financial returns through the life of the well.

We are committed to partnering with our customers to unlock these benefits that autonomous drilling technologies can provide. Another important differentiation of our technology offerings involves not only the technology platform, but also the business model we have developed. Our strategy is unique. Most of our digital technology and software is designed and available on all rigs not just H&P FlexRigs. This is an important distinction because it allows our customers to utilize the software and datasets across their entire fleet of contracted rigs.

So, before turning the call over to Mark, I want to close with recognizing that the company achieved excellent operational results and several technical accomplishments during the quarter. Our ability to adapt and respond to uncertain market conditions while securing new opportunities for long-term success is paramount. These achievements are possible without the efforts of our people working as a team to deliver on our goals and by forming strong partnerships with our customers. These efforts exemplify H&P's commitment to excellence.

And now, I'll turn the call over to Mark.

Mark W. Smith -- Vice President and Chief Financial Officer

Thanks, John. Today, I will review our fiscal second quarter 2019 operating results, provide guidance for the third quarter, update full fiscal year 2019 guidance as appropriate, and comment on our financial position.

Let's start with highlights for the recently completed second quarter. The company generated quarterly revenues of $721 million versus $741 million in the previous quarter. The quarterly decrease in revenue is primarily due to a decrease in the average number of rigs working in the U.S. Land segment as expected.

Total direct operating costs incurred were $443 million for the second quarter versus $489 million for the previous quarter. The decrease is primarily attributable to lower than expected daily operating costs in U.S. Land and to the $18 million effect of a one-time legal settlement in the first fiscal quarter. The lower operating costs experience were in both regular daily operating maintenance and supplies, as well as in rig reactivation costs.

General and administrative expenses totaled $44 million for the second quarter. This is below the run rate for our full year guidance due to the timing of certain company projects, but our full year guidance for G&A has not changed. Our effective income tax rate from continuing operations was approximately 26% for the second fiscal quarter, which was in line with our annual expected rate and includes incremental state and foreign taxes as well as the U.S. statutory rate.

Summarizing the overall result of this quarter, H&P earned $0.55 per diluted share versus $0.17 in the previous quarter. Second quarter earnings per share was negatively impacted by a net $0.01 per share of selective -- select items as highlighted in our press release. Absent the select items, adjusted diluted earnings per share were $0.56 in the second quarter versus an adjusted $0.42 during the first fiscal quarter.

Capital expenditures for the second quarter of fiscal 2019 were $134 million. So when combined with Q1 CapEx, we have expended approximately 65% of our full year CapEx guidance as revise last quarter. This lines up with our guidance that fiscal 2019 CapEx would be front-loaded.

Turning to our four segments beginning with U.S. Land segment. We exited the second fiscal quarter with 226 contracted rigs, which was a decrease of approximately 1% than the number of active rigs quarter-to-quarter. H&P maintained over 20% U.S. Land market share from quarter-to-quarter. I will discuss this in more detail in a moment. But we anticipate that our rig count will approach a current cycle bottom in the third fiscal quarter, and our super-spec rig class will maintain an average utilization level of approximately 90%.

H&P as leading market share in the top three U.S. basins 24% in the Permian, 39% in the Eagle Ford and 26% in the Scoop/Stack. Our activity levels in each are 114, 39 and 25 rigs contracted respectively. Despite slowing market conditions in the second fiscal quarter, we were able to maintain pricing in the type super-spec market space.

Our average rig revenue per day excluding early termination revenue increased to $25,624 for the quarter in line with our guidance. Included here is the increasing customer adoption of our FlexApp offerings that are approximately $300 per day per rig in revenues across the fleet from $250 last quarter. The average adjusted rig expense per day decreased to $14,195. This is below our previously guided range due to lower than expected maintenance and supplies expenses and lower reactivation costs.

Looking ahead to the third quarter of fiscal 2019 for U.S. Land. While putting second fiscal quarter upgrades to work under term contracts, we also experienced a number of late quarter rig releases. We are currently seeing net rig releases moderate, which will result in a sequential decrease of approximately 4% to 6% in the quarterly number of revenue days. This translates to an average rig count of approximately 220 rigs during the third quarter, which is approximately where we are as of today's call.

To reiterate my previous comment, we expect super-spec utilization to remain in the 90% range during the third quarter. Compared to the second quarter at $25,624 per day, we expect the adjusted average rig revenue per day to be flat within a range of $25,500 to $26,000. Our average day rate in both the spot and term markets is in the low to mid-20s range and leading edge super-spec FlexRig pricing is in the mid-20s.

The normalized average rig expense per day directly related to rigs working in the U.S. Land segment remains constant at $13,700 per day. This per day figure excludes the impact of expenses directly related to inactive rigs, the idling of released rigs and the upfront reactivation expenses related to rigs that have been idle for a significant amount of time.

Including these three costs, the average rig expense per day is expected to be in a range of $14,250 to $14,750 for the third quarter. Note that with the reduced number of upgrades beginning in this quarter, upfront reactivation expenses will continue to come down while moving the average rig expense per day toward the normalized expense per day number of $13,700 through time. However, note that the third quarter will still see reactivation expenses from upgrades that commenced toward the end of the second quarter.

We had an average of 149 active rigs under term contracts during the second quarter, and today that number is 142 rigs or about 65% of our 220 working rigs. We expect to have an average of 137 rigs under term contract in the fiscal third quarter and 124 rigs in the fourth quarter earning the current average day rates.

For the 79 rigs that remain under term contract in fiscal 2020, the associated day rate is approximately $250 per day higher than today's average. We receive $1.2 million in early termination revenue in the second quarter and have only experienced a couple of early terminations during this calendar year. The remaining terms on these cancellations were not material to our overall revenues.

Regarding our International Land segment, the number of quarterly revenue day is decreased 11% in the second fiscal quarter in line with our guidance and due primarily to two rigs Stacking and Colombia early in the quarter as expected. The adjusted average rig margin per day in the segment increased by $1,679 to $11,861 in the second fiscal quarter. The increase was primarily due to higher than expected rig margins which were offset by fewer working rigs in Colombia.

As we look toward the third quarter of fiscal 2019 for international, quarterly revenue days are expected to be flat to down slightly with an average third quarter rig count of approximately 17 active rigs in the segment. The average rig margin is expected to decrease slightly to between $9,000 to $10,000 per day during the third fiscal quarter, due to only one active rig in Colombia absorbing that country's overhead costs.

As John mentioned earlier, we are expecting to send our first international super spec rig to Argentina. This rig is expected to commence operations with an international E&P customer midway through the fourth fiscal quarter under a term agreement that will be accretive to our average international margins. In addition, just this week, we also signed separately an LOI to reactivate at Flex4 in the country of Bahrain increasing to two Flex 4s in that country.

Turning to our offshore operations segment, we continued with six active rigs during the second fiscal quarter, but a second rig moved to standby rate which negatively impacted revenues for the quarter. The average rig margin per day decreased sequentially due to the lower standby rate being in effect for most of the quarter as well as higher self-insurance expenses.

As we look toward the third quarter of fiscal 2019 for the offshore segment, we currently have the six of eight rigs contracted. The average margin per day is expected to increase to a range of $9500 to $10,500 during the third quarter as two rigs are anticipated to move from the standby rates to full operating rigs.

Now looking at H&P Technologies segment. As John mentioned, AutoSlide is now commercial and our plans are to methodically roll it out to our active bases. Timing and rate of adoption of new technology is hard to predict at an early juncture, but we believe AutoSlide provides a unique path toward differentiated pricing models for drilling services that are inclusive of wellbore quality and placement services.

From a historical day rate perspective, the potential margin accretion of this software service begins at the anecdotal market day rate for a directional driller of approximately $2,000 per day. Added to this would be an amount reflecting the value added to our customers for consistent repeatable quality.

As previously guided, we are on a path toward autonomous drilling and we are continuing to make significant research and development investments which we believe will result in new services and increased market share over time. Now let me look forward on corporate items for the remainder of the fiscal year.

Our current revenue backlog for the U.S. Land fleet for rigs under term contracts which we define as rig contracts with original fixed terms of at least six months and that contain early termination provisions is approximately $1.4 billion. Capital expenditures for the full fiscal year 2019 are expected to remain in the revised range we guided to in January which was $500 million to $530 million.

As a reminder, capital investment in our fleet is comprised of three distinct buckets. Bucket 1 contains capital expenditures to upgrade and convert flex rigs to super-spec capacity. Much of this first bucket was front-loaded in the first two fiscal quarters with a total of approximately five walking rig upgrades planned for the remainder of the fiscal year which are backed by term contracts.

The second bucket consists of flex rig capital maintenance which typically ranges between $750,000 to $1 million per active rig per year. The third bucket of 2019 CapEx is comprised of two items. One, fiscal year 2019 catch up on bulk spare equipment purchases to support the increased scale of our super-spec fleet over the last two years; and two, hire capital rig reactivation cost due to the average idle time of reactivated rig being close to four years of stacking.

Our CapEx range includes incremental expenditures to send the aforementioned super-spec rig to Argentina, while leaving our overall CapEx range unchanged. We expect to see reduced maintenance CapEx given our current rig activity levels and these along with expenditures for certain bulk purchases will correlate closely with our operating rig counts.

Despite the Q2 timing results, our general and administrative expenses for the full 2019 fiscal year are expected to be roughly flat from 2018, approximately $200 million in total. G&A will somewhat fluctuate from quarter-to-quarter due to the timing of various company initiatives. In addition to the U.S. statutory rate, we continue to incur incremental state and foreign income taxes, and we are still projecting our annual effective tax rate to be in the range of 26% to 30%.

And now looking at our financial position, Helmerich & Payne had cash and short-term investments of approximately $270 million at March 31, 2019. Including our expanded and extended revolving credit facility availability, our liquidity was approximately $1 billion. Our debt to capital at quarter end was approximately 10% the lowest among our peer group. We have no debt maturing until 2025.

Our balance sheet strength, liquidity level and term contract backlog provide H&P the flexibility to adapt to market conditions, take advantage of attractive opportunities and maintain our long practice of returning capital to shareholders through our dividend. As we look ahead into the planning horizon, we are confident in the future potential cash flow generation of our fleet.

Using our cash flow from operations this second quarter of approximately $200 million as a simple planning proxy, we could generate $800 million of annual run rate cash flow from 220 active U.S. Land rig count together with our 23 current active international and offshore rigs.

Assuming only maintenance CapEx at the annual midpoint guidance of $875,000 per active rig our, CapEx annual run rate would be approximately $210 million. The remaining cash flow in this static simple run rate example $590 million would be available for our long-standing dividend and other capital allocation opportunities.

That concludes our prepared comments for the second fiscal quarter. Let me now turn the call over to Priscilla for questions.

Questions and Answers:

Operator

(Operator Instructions) And we'll take our first question today from Jud Bailey with Wells Fargo. Your line is open.

Jud Bailey -- Wells Fargo -- Analyst

Thanks, good morning. My first question, I think is, Mark, wanted to follow-up on one -- some of your comments on operating cost per day. I think you indicated, you still expect to, I think, ultimately get to kind of the normalized level of around $13,700. Is that a level that we should anticipate or can start to think about for the September or the December quarter? Do you have a line of sight that's something that makes sense based on the slowdown in reactivation super-spec upgrades?

John W. Lindsay -- President and Chief Executive Officer

Well, thanks for the call and question. As we look at it, there is a breakdown currently of about $400 per day for upfront reactivation expenses. So, I would assume, Jud that is the part that you can start actively modeling downward to mere slower cadence. However, we still have about $330 per day, related to the inactive rig count that we have idle, as well as the because two idle rigs that we've experienced recently. So, that bucket is a little bit harder to determine a direct line of sight to you.

Jud Bailey -- Wells Fargo -- Analyst

Okay, all right. Well, that's helpful though. My follow-up I think is a part for John. Could you maybe talk little more about AutoSlide and now that you're commercializing it, maybe talk a little bit about what you're hearing from customers and how quickly that the rollout maybe there and how quickly you think you may get more systems out in the field?

John W. Lindsay -- President and Chief Executive Officer

Okay, Jud. It's very hard at this stage to judge the speed of the rollout as Mark mentioned in his prepared remarks. We have a design in terms of rolling it out to various basins, and we started with Midland, and we're going -- we're in the Eagle Ford now as we said, and then in a couple of months, our intent is to deploy into the Scoop/Stack play, but our intent is to have AutoSlide in all of the basins.

And so, as you think about what we're doing in the automation phase, we're actually using machine learning and the Motive algorithm and the FlexRig operating system. So these -- you know, the great news is these algorithms continue to learn and learn the basin, kind of the specific differences and/or challenges that each basin may provide. And so, again, there will be more to come on it. We're working for four customers now, three in Midland, and one in the Eagle Ford. And again, we're excited about the performance thus far, and again, this is the automation of the sliding function when drilling a horizontal well. So, that's kind of the overview.

Jud Bailey -- Wells Fargo -- Analyst

Okay. All right. Well, I'll turn it back, thanks. Thanks a lot.

John W. Lindsay -- President and Chief Executive Officer

Thanks a lot.

Operator

Thank you. We'll take our next question today from Tommy Moll with Stephens, Inc. Your line is open.

Tommy Moll -- Stephens, Inc. -- Analyst

Good morning, and thanks for taking my questions.

John W. Lindsay -- President and Chief Executive Officer

Good morning, Tommy.

Tommy Moll -- Stephens, Inc. -- Analyst

I wanted to follow-up with one AutoSlide question, you mentioned in the prepared remarks, a comparison to $2,000 a day for directional driller. How should we think about being able to capture the full value that you're going to deliver to customers with AutoSlide, and as a day rate framework the right way for us to think about it, or is there an alternative strategy to go to market here with AutoSlide?

John W. Lindsay -- President and Chief Executive Officer

Yes, I think, Tommy, we're definitely not -- we're definitely not looking at a commercialization model that's based on a day rate. Mark was simply using that as just kind of an idea of part of the value proposition that a customer can see right off the bat, because AutoSlide does allow for the elimination of the directional drillers on the rig side. Now, we have directional drillers that are off-site that are watching the wells real-time, but it enables you -- as you think about some of the industry themes over the last two, three years, and one is automation, one is more of a demanding being less reliant on having as many people on rig side.

And so, I think it's one of those steps that allow that to happen. Part of the process of the rollout of AutoSlide and other reason for taking -- maybe taking a little slower than what we would normally take it. One of the things that's important is to understand the value proposition. And if you go back to the early days of the FlexRig, of course we were building -- we started off of building two rigs a month with the first luxury that we rolled out, but there was definitely an adoption phase, and our industry has a tendency to adopt kind of at a slower pace.

But again as you think about major themes that we've seen as an industry over the last couple of years, there's definitely a desire and need to utilize digital technology, to utilize higher levels of technology, and looking at demanding. So that's really the opportunity. So we have to jointly work on this value proposition with the customer. Again, there's the automation piece, but there's also the tortuosity, less tortuosity, which delivers on things like better downhole tool life. It require -- it allows downhole tools to last longer, which means we're tripping fewer times, which means we're lowering risk at the rig site.

And then again, I'd mentioned in my remarks that I mean there are some industry studies out there that are saying that less tortuous wellbore has the potential for higher oil production. So those are big deals and every customer is going to be different every situation is going to be different. So that's kind of the outlier. It's all about us figuring out ways to deliver higher levels of value for our customers. And of course we're making significant investments not only dollar wise, but management, time, structure, standing up H&P Technologies, all those sorts of things are I think are very important in the success of the product.

So, again it's all about customer value, and I think when the customer see the value, which we've seen a lot at this point we think they're going to be in a position to want to pay for that perform.

Tommy Moll -- Stephens, Inc. -- Analyst

Thank you, John. That's all helpful. And as a follow-up, I wanted to switch gears and talk about the international opportunity. You called out the LOI to send a super-spec to Argentina. Can you give us anything there, just in terms of the back story, how long conversations had been going on? Anything anecdotally you could share given this is a pretty important update to have your first deployment internationally.

And then going forward, how big of an opportunity do you see? You mentioned in the prepared remarks, it not only involves the rig but also technology potentially over time. So, whether you answer that specific to Argentina or more just generally about the opportunity to export some of your capability, it would be helpful. Thanks.

John W. Lindsay -- President and Chief Executive Officer

Sure. Thanks, Tommy. Well, on the super-spec again, as a reminder, we have, I think, 12 or 13 Flex3s in Argentina now. They aren't super-spec, they have not been upgraded to super-spec, again one of the advantages that we have is the ability to upgrade those to super-specs. So this is the first fully upgraded super-spec rig coming out of FlexRig that's going down to Argentina. Again, it's a great opportunity. It's something we've been working on for, I don't even know the timing, probably over the last couple of months.

I think there is additional opportunity for us to send more of the FlexRig super-spec capacity that's in the U.S. to Argentina specifically and also into other countries over time. And then obviously there's the opportunity to upgrade existing rigs on the ground, super-spec capacity. So I think that's a great position for us. It's depending on what the market does here in the U.S. We've got additional opportunities outside of the U.S.

As far as H&P Technologies, specifically Motive and MagVar, both of those technologies are applicable to international markets, both on FlexRigs, as we've said, as well as on other rigs that our customers are contracting. And I think there's a lot of interest associated with both. And so I would expect in the coming quarters that we will be able to talk more about that and be able to demonstrate some of the traction, some of the adoption that we've seen with these other technologies.

You know, we've -- I think we may have mentioned in the past that, there's always the opportunity to have the technology pull the rig through as a one potential, but definitely there is interest both in the Middle East and in South America for our technology offerings.

Tommy Moll -- Stephens, Inc. -- Analyst

Thank you, John. That's all for me.

John W. Lindsay -- President and Chief Executive Officer

All right, Tommy. Thank you.

Operator

Thank you. And we'll take our next question today from Scott Gruber with Citigroup. Your line is open.

Scott Gruber -- Citigroup -- Analyst

Yes, good morning.

John W. Lindsay -- President and Chief Executive Officer

Good morning, Scott.

Mark W. Smith -- Vice President and Chief Financial Officer

Good morning.

Scott Gruber -- Citigroup -- Analyst

A question on the extra costs in U.S. Land. Just ballpark, what is the cost to either a rig relative to the cost to reactivate, I know it will differ on a rig-by-rig basis, but kind of ballpark, what is the delta between those two?

Mark W. Smith -- Vice President and Chief Financial Officer

Well, I think, I might have mentioned in my prepared remarks that the reactivation calls can be about -- from an OpEx perspective, about a $1 million to $1.5 million is really going to depend on the particular rig. So the idling cost is substantially less than that. So that's why the range of those buckets for reactivation costs versus idling costs have a delta. So we will again see regression of the reactivation costs through time that will mirror the slowdown in the cadence of upgrades. The idling cost should come off a little bit in that bucket just because we are seeing here early in the third quarter, the leveling of the fleet count, but we will continue to incur the static idling cost for rigs that have long been inactive.

John W. Lindsay -- President and Chief Executive Officer

Scott, I'm going to add a little bit more color on that as well. I guess just so we're clear. Those reactivation costs that Mark mentioned are related to rigs that have been idle for a very long period of time. If you look at the reactivation of the most recently idled rigs, those reactivation costs are very, very low. And in fact, even the idling expense is very low because as compared to what we saw in 14 and 15, 16 timeframe, when we were idling the rigs then, we took great care to do a lot because we realized those rigs weren't going to go back to work in a couple of weeks or a couple of months.

So the rigs that we idled recently, we fully believe we're going to go back to work, and in near term, in fact, a lot of them have. We continue to have this ongoing churn, which is common, even in the strongest of markets. The churn level is higher today, obviously than it was say, four or five months ago, but we still have rigs that are idled recently, a lot of those, some of those have gone back to work. It's just a continual churn. So I just wanted to make certain that you recognize with the most recently idled rigs to reactivate is a very, very low cost.

Scott Gruber -- Citigroup -- Analyst

Yes. I appreciate the color. And then I think Mark you called out $330 a day of costs for the inactive rigs. So if we're just caught flat on the rig count and everything normalizes, should we be taking closer to 14K as the normal daily rate cost of 37 plus the three in change?

Mark W. Smith -- Vice President and Chief Financial Officer

It will be a little less than that Scott, because the $330 is a combination of the inactive legacy fleet, if you will, and the cost to idle rigs that have recently been idle. And as those costs of, let's say 200 or so thousand per day when we've been idling rigs in this calendar year that will come off with this moderation that we've experienced. So, we always see some churn, but -- what the ultimate number is just going to be reducing, but they -- you know, it's going to what the ultimate number is just going to be, it's going to be up to the market.

Scott Gruber -- Citigroup -- Analyst

Okay. And then one on CapEx, I appreciate the additional color on where your maintenance stands getting your current activity set. In the second half the year, it looks like you'll spend $180 million, $190 million, or about $90 million, $95 million per quarter. Again, ballpark, is that a good run rate to think about for fiscal '20 assuming no major swings in rig count, or would it be lower than that given your maintenance level expense?

Mark W. Smith -- Vice President and Chief Financial Officer

I think it would be lower than that. If you think about the three buckets I mentioned in the prepared remarks, if you just assume that we were in -- as a planning proxy again, flat rig count next year and you eliminated the upgrade bucket for this illustrative example. You also would essentially remove the bulk catch-up bucket as well. So, long way to say, you get down to just the regular maintenance on the active rig count. And that is really how if -- that's really how I think about modeling the next year.

Scott Gruber -- Citigroup -- Analyst

I appreciate the color. Thank you.

John W. Lindsay -- President and Chief Executive Officer

You are welcome.

Mark W. Smith -- Vice President and Chief Financial Officer

Thank you.

Operator

Thank you. And we'll take our next question today from Kurt Hallead with RBC. Your line is open.

Kurt Hallead -- RBC Capital Markets -- Analyst

Thank you. Good morning.

John W. Lindsay -- President and Chief Executive Officer

Good morning, Kurt.

Kurt Hallead -- RBC Capital Markets -- Analyst

Hey, it's a great summary. I appreciate all the color, commentary and insights. So, I think, John, what I think I'd like to maybe focus on a bit is the dynamics around the new technology, the AutoSlide, the applications and algorithms, and the new business model. And just want to -- want to just be clear as well on that dynamic.

So the new segment you have is a technology segment. So first and foremost, all the AutoSlide and algorithms and apps and everything else, that's going to be housed within that new technology segment. And I say that mainly because you're going to differentiate the revenue generation for that business vis-a-vis just adding a day rate for that. Am I understanding that correctly, like all that technology driven business will be in that specific segment, it's not going to be layered into a day rate?

John W. Lindsay -- President and Chief Executive Officer

Kurt, on the FlexApps, the FlexApps are an IDC rather than an HPT segment, but they are not day work type applications. We're not pricing those generally in that sort of a fashion. We're generally pricing them in a different type of a business model. The rest of the AutoSlide and Motive and MagVar, those are HPT.

In our industry, it's hard to -- it's been hard to not go down the day rate model. I think it's something that's kind of a legacy piece. And again, our effort is to develop different sorts of pricing models. We've been successful in doing that in some cases and other cases, it has been more of a day work type or performance type of model if you will, so that's the separation.

Kurt Hallead -- RBC Capital Markets -- Analyst

Okay, that's helpful. So you spoke about working with the customer base in defining and understanding the value proposition of what AutoSlide and the FlexApps are going to bring to the table. Obviously, this is a discussion that you guys should be very comfortable with ever since the advent of the HP FlexRigs into the marketplace, you've been able to demonstrate that value prop. How do you find these discussions going with the customer base and then kind of what have you been learning as you've been having these discussions around how the E&Ps kind of view this new technology dynamic?

John W. Lindsay -- President and Chief Executive Officer

I think, for the most part, our customers have been very embracing. I mean, I think, using an example of -- we've got, I think, MagVar is on close to 300 rigs today and close to a 100 for -- on H&P. Motive is still -- just still under 30 rigs. But the Motive challenges are much different than the MagVar as an example. But I think in general, they've been very embracing. It's not a question of, if the technology works or if the technology adds value. It's -- there's a certain element of change management that is always a challenge when you're introducing new technologies, regardless of the industry, and again, our industry has some of those challenges.

But in general, I think they're very embracing. We have a lot of interest, particularly on automation and being able to drive another level of reliability for customers. As I said in my remarks, it's not effective enough today to only drill a very fast well. There's other elements of that, and as there's reliability, and there's less tortuosity, and there's better placement. And so, I think that's really important.

Kurt Hallead -- RBC Capital Markets -- Analyst

Yes, it's good, it's great. And a follow-up, I was talking about maybe the super-spec rig dynamics. I know, you guys always provide pretty good information around, what you think the market size is and how many rigs are out there that are currently super-spec capability? And how many rigs could potentially be upgraded? Can you give us a quick snapshot on that again?

John W. Lindsay -- President and Chief Executive Officer

I think if you use our strictest definition that we've utilized, I think there's around 520 super-spec rigs at with another 150 using that strictest definition that could be upgraded. And I think maybe half of those are actually working today. And then if you expand the definition, and if you look at again, what we've said overtime is, look at what rigs are actually working and what their size might be. There are some either larger hookload or a larger horsepower drawworks that have -- that have been outfitted to some of the super-spec capacity. And I think that's another 100 and maybe 120 rigs or so that are active in the market today. And so that gives you what a 650 or so that are active.

I think it's also important when we have this conversation that we also mentioned that there's still about 230 legacy rigs, mostly SCR but even some mechanical rigs that have been upgraded in some capacity or another to do some of this more challenging horizontal work. And those rigs are out there working today, obviously, much fewer SCR rigs working today than what you saw in 2014.

There's -- I don't know what the right number is, probably 700 -- 600 or 700 rigs that are that are gone. So I think there's a real opportunity to deliver a much higher level of value proposition to customers and continue to disrupt that legacy rig fleet business. And, I fully expect that that's going to continue to happen over the coming years. And particularly, I think in an environment like we see today, where customers aren't growing their fleets in a large scale way, they're looking at their rigs, and they're looking at them very closely, quarterly, having quarterly performance reviews and determining who is performing and who is not. And in those situations, I think you'll find where the AC drive, and specifically FlexRigs going to take some additional market share.

Mark W. Smith -- Vice President and Chief Financial Officer

And just to add to that John, as we said earlier, we have 230 super-spec rigs ourselves here at H&P. And currently we have another 47 that are available for upgrade, eight of those are working. So we still have -- certainly still have added capacity within our fleet.

Kurt Hallead -- RBC Capital Markets -- Analyst

All right. That's awesome. Thanks for that info. I appreciate it.

Mark W. Smith -- Vice President and Chief Financial Officer

Thank you, Kurt.

John W. Lindsay -- President and Chief Executive Officer

Thanks, Kurt.

Operator

Thank you. And we'll go next today to Sean Meakim with JP Morgan. Your line is open.

Sean Meakim -- JP Morgan -- Analyst

Thank you. Good morning.

John W. Lindsay -- President and Chief Executive Officer

Good morning, Sean.

Sean Meakim -- JP Morgan -- Analyst

I was hoping, you could just maybe clarify the cadence of upgrades for fiscal '19, just make sure we have the number straight. I think we have 14 that were completed in fiscal 1Q, I think nine in the second quarter, and I think the release talked about two or three more in the current quarter, earlier in your comments, may be you said there was five more for the year. So I just want to make sure that those five or maybe the two or three is probably inclusive of the five? So something -- we're talking about something like 28 rigs. I think the budget is set around $180 million to maybe 6.5 million per (ph) that seems to kind of foot with your prior guidance of walking versus skid system, does that all seem to fit properly?

Mark W. Smith -- Vice President and Chief Financial Officer

Sean, yes, it does. Your math is -- your math is spot on.

Sean Meakim -- JP Morgan -- Analyst

All right. It's not always the case. So, I appreciate that. And then just on international, just to get a bit more of a clarification, could you maybe give us a little more detail, what's driving the lower active international rig count quarter-over-quarter and the margin compression. Is it more -- as rig moves there maybe some mix shift within the rigs that are working, just wanted to get a little more understanding there, if we could?

Mark W. Smith -- Vice President and Chief Financial Officer

In the call in January, we had provided some guidance that we expected the Colombia market to contract a bit. We really see that market more directly correlating to oil price movements for this quarter upcoming that we're giving guidance for, we do not see any revisions back even with the oil price trajectory that we've seen recently, but stay tuned.

Sean Meakim -- JP Morgan -- Analyst

Got it. Okay, fair enough. And one last piece of international. We talked a little bit about the Argentina contract and then the Flex4 going to rain, how do you think about rest of the world ex-Argentina appetite for incremental rigs that can be deployed internationally? And then long term the appetite for super-spec rigs in some of these other markets?

Mark W. Smith -- Vice President and Chief Financial Officer

We'll -- I'll just make an introductory comment or two here. As it relates to the unconventional play as we've talked, and John specifically talked about on previous calls, we've had tremendous success in Argentina that mirrors the success we've had in the U.S. Land. We certainly aim to be a part of that continuing story there, and next, we really look for unconventional to move to the Arabian Peninsula.

So several different countries in the Middle East, and I think, on the January call we even mentioned some of the inbound inquiries we've had there, and those are -- those inquiries are for AC rigs in particular just exemplary of this Flex4 LOI that we have in brain that we've just done this week. But in Argentina, the super-spec going there -- our first super-spec to deploy internationally is really exciting, because it talks about how the unconventional play in the Vaca Muerta is actually getting more complex and laterals are getting longer. So the need for the super-spec will come into play more through the development in this field.

John W. Lindsay -- President and Chief Executive Officer

Yes, I would just add, Sean. And of course we've seen this as an opportunity for a long time and we've prefaced it by saying when we see unconventionals more horizontal wells internationally and when you get to the point where there's a need for more of a manufacturing type process then H&P has the rigs in the capacity and the solution really to deliver in that situation. So really -- that's really I think what has to happen as we've got to see those types of programs developed like what we've seen in Argentina and I think that begins to open up the opportunities for us.

Sean Meakim -- JP Morgan -- Analyst

Sure that all make sense. Thank you, both. I appreciate it.

John W. Lindsay -- President and Chief Executive Officer

Thank you.

Mark W. Smith -- Vice President and Chief Financial Officer

Thanks.

Operator

And we'll go next today to Brad Handler with Jefferies. Your line is open.

Brad Handler -- Jefferies & Co -- Analyst

Hi. Thanks guys for squeezing me in. I guess I'm just have one question related to Argentina and it's more just you can help us think about things aren't as good in Argentina as they were very recently right inflation is clearly creeping up as a risk in the IMF, it sounds like it's going to get involved and whatever, how can you help us think about risks as it relates to your business. I think your contracts are all dollar-denominated. So, that's good, but what about just labor disruption or other factors that we may have to think about if Argentina unfortunately goes the wrong way.

Mark W. Smith -- Vice President and Chief Financial Officer

I'll start of, Brad. As it relates to the contracts you corrected there. The contracts are tied to the U.S. dollar, technically paid in pesos. But in literally there is a same day and billing and payment, so we can convert right back to U.S. dollars. From a revenue perspective, the U.S, dollar and the way to think about it from in country cost perspective. We have a mix. We have several of our inputs pieces of equipment, et cetera, that will have some U.S. dollar denomination. We also have some component of expat personnel, which are tied to the U.S. dollar and then locally cost of the expenses are in the peso and offset each other. So that is kind of the high level, we have. So, in other words, we have been pretty well shielded from the hyperinflationary position there at H&P and continue to work to look to keep that state. As it relates to the labor market, I'll let John comment.

John W. Lindsay -- President and Chief Executive Officer

Yes, Brad. We -- there are challenges at times with labor unions in Argentina, but our experience in vaca muerta have been very positive. I think particularly as compared to other areas that we've worked in Argentina in that further south. I think in general though it kind of comes back to this general overarching theme that you've heard us come back to many, many times and that is working internationally has a whole another level of challenges and risks that we at least up to this point in time haven't faced in the U.S.

That's one of the reasons why we've grown our fleet in the way that we haven't made the investments that we've made in U.S. Land, and we haven't been able to grow as much internationally, and it's because we haven't been able to get term contracts you can't make the returns that you would really like to make because of the risk associated with it. So it's one of the things that we've come to use to and yes, there's a lot of questions in Argentina, the upcoming election is obviously is one and we'll see how that turns out.

Brad Handler -- Jefferies & Co -- Analyst

Okay, fair enough. Yes, I guess, I think, that's it. I will turn it back. Thank you.

John W. Lindsay -- President and Chief Executive Officer

Okay. Thank you.

Mark W. Smith -- Vice President and Chief Financial Officer

Thank you, Brad.

Operator

One moment please. All right, and this does conclude our Q&A session for today. I'll turn the call back to John Lindsay for any closing remarks.

John W. Lindsay -- President and Chief Executive Officer

Okay. Well, thank you. I appreciate everyone's attendance today and being interested in H&P, again thanks to all of our employees that work hard every day to contribute to the H&P way. So, thank you very much. Have a great day.

Operator

This does conclude today's program. Thank you for your participation. You may disconnect at any time.

Duration: 60 minutes

Call participants:

Dave Wilson -- Director of Investor Relations

John W. Lindsay -- President and Chief Executive Officer

Mark W. Smith -- Vice President and Chief Financial Officer

Jud Bailey -- Wells Fargo -- Analyst

Tommy Moll -- Stephens, Inc. -- Analyst

Scott Gruber -- Citigroup -- Analyst

Kurt Hallead -- RBC Capital Markets -- Analyst

Sean Meakim -- JP Morgan -- Analyst

Brad Handler -- Jefferies & Co -- Analyst

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